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Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

10-K/A
Amendment No. 1
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20202021
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
        to        
to
Commission file number
1-10934

ENBRIDGE INC.
(Exact Name of Registrant as Specified in Its Charter)

Canada
98-0377957
(State or Other Jurisdiction of
Incorporation or Organization)
(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
Trading Symbol(s)
Trading
Symbol(s)
Name of each exchange
on which registered
Common Shares
ENB
ENB
New York Stock Exchange
6.375%
Fixed-to-Floating
Rate
Subordinated Notes Series 2018-B due 2078
​​​​​​​
ENBA
ENBA
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes
No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation
S-T
232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes
No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated
filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging"emerging growth company”company" in Rule
12b-2
of the Exchange Act.
Large Accelerated FilerAccelerated Filer
Non-Accelerated FilerSmaller reporting company
Non-Accelerated
Filer
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2
of the Exchange Act).    Yes  
    No  
Indicate by check mark whether the registrant has filed a report on and attestation to its management’smanagement's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. Yes
No
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes
No
The aggregate market value of the registrant’s common shares held by
non-affiliates
computed by reference to the price at which the common equity was last sold on June 30, 2020,2021, was approximately US$59.277.7 billion.
As at February 5, 2021,4, 2022, the registrant had 2,025,495,6032,026,274,277 common shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:
Not applicable.


Table of Contents

EXPLANATORY NOTE

Enbridge Inc., a corporation existing under the
Canada Business Corporations Act
, qualifies as a foreign private issuer in the United States of America (US) for purposes of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)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”)(SEC) instead of filing the reporting forms available to foreign private issuers.

Enbridge Inc. preparesintends to prepare and filesfile 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 itsthis Form
10-K
from its management proxy circular.
Enbridge Inc. filed its Annual Report on Form
10-K
for the fiscal year ended December 31, 2020 (the “Original Filing”) on February 12, 2021. In Accordingly, in reliance upon and as permitted by Instruction G(3) to Form
10-K,
Enbridge Inc. iswill be filing an amendment to this Amendment No. 1 on Form
10-K/A
in order to include in the Original Filing 10-K containing the Part III information not previously included in the Original Filing.
Except as stated herein, no other changes have been made to the Original Filing. The Original Filing continues to speak as of the date of the Original Filing, and, otherlater than the information provided in Parts III and IV hereof, we have not updated the disclosures contained in the Original Filing to reflect any events which occurred at a date subsequent to the filing of the Original Filing.
In this Amendment No. 1 on Form
10-K/A,
the terms “Enbridge,” “we,” “our” and “company” mean Enbridge Inc. “Board of Directors” or “Board” means the Board of Directors of Enbridge. “Enbridge shares” or “common shares” mean common shares of Enbridge. All dollar amounts are in Canadian dollars (“C$” or “$”) unless stated otherwise. US$ means United States of America (“U.S.”) dollars.
All references to our websites and to our Canadian management proxy circular, dated March 2, 2021 and filed with the SEC on March 8, 2021 as Exhibit 99.1 to our Current Report on Form
8-K
(the “Circular”) contained herein do not constitute incorporation by reference of information contained on such websites and the Circular and such information should not be considered part of this document.


PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
DIRECTORS OF REGISTRANT
Director profiles
Shareholders elect directors to the Board for a term of one year, expiring at120 days after the end of the next annual meeting. The profiles that follow provide information about the nominated directors, including their backgrounds, experience, current directorships, Enbridge securities held and the Board committees they sit on. Additional information regarding skills and experience of our directors can be found beginning on page 15.fiscal year covered by this Form 10-K.

 
Pamela L. Carter
 
 
Age 71
Franklin, Tennessee, USA
Independent
 
Director since
February 27, 2017
 
Latest date of retirement
May 2025
 
2020 annual meeting votes for: 85.23%
   
 
 
Ms. Carter was the Vice President of Cummins Inc. and President of Cummins Distribution Business, a division of Cummins Inc., a designer, manufacturer and marketer of diesel engines and related components and power systems, from 2008 until her retirement in 2015. Ms. Carter joined Cummins Inc. in 1997 as Vice President – General Counsel and Corporate Secretary and held various management positions within Cummins. Prior to joining Cummins Inc., Ms. Carter served in the private practice of law as partner and associate and in various capacities with the State of Indiana, including Parliamentarian in the Indiana House of Representatives, Deputy Chief-of-Staff to governor Evan Bayh, Executive Assistant for Health Policy & Human Services and Securities Enforcement Attorney for the Office of the Secretary of State. She served as the Attorney General for the State of Indiana from 1993 to 1997 and was the first African-American woman to be elected state attorney general in the U.S.A. Ms. Carter holds a BA (Bachelor of Arts) from the University of Detroit, MSW (Master of Social Work) from the University of Michigan, J.D. (Doctor of Jurisprudence) from McKinney School of Law, Indiana University, and Public Administration from Harvard Kennedy School. Ms. Carter received a 2018 Sandra Day O’Connor Board Excellence Award honoring her for her demonstrated commitment to board excellence and diversity. She also received an award as one of the top 100 board members from NACD in 2018 and top 25 director from Black Enterprise, 2018.
 
 
 
 
Enbridge Board/Board committee memberships
 
     
 
2020 meeting
attendance
1
 
 
 
 
Board of Directors
 
    
 
6 out of 6
  
 
 
 
100%
 
 
 Corporate Social Responsibility     4 out of 4   100% 
 Governance (Chair)     3 out of 4   75% 
 
Human Resources & Compensation
2
     2 out of 2   100% 
 
Total
 
 
    
15 out of 16
 
  
 
 
94%
 
 
 
 
 
Enbridge securities held
3
 
            
      
Enbridge
shares
  
DSUs
4
     
 
Total market value of
Enbridge shares & DSUs
5
  
Minimum
required
6
 
   
 
 
 
44,639
 
 
  11,744     
$2,494,943
   $925,880 
 
 
Other board/board committee memberships
7
 
            
 
 
Public
7
 
            
 
 
Hewlett Packard Enterprise Company
(public technology company)
 
 
    
 
Director
Chair, human resources and compensation committee
Member, audit committee
 
 
 
 
 
 
Broadridge Financial Solutions, Inc.
(public financial services company)
 
 
    
 
Director
Chair, audit committee
Member, governance and nominating committee
 
 
 
 
 
 
Former
U.S.-listed
company directorships (last 5 years)
 
      
    
 
CSX Corporation
 
              
      
 
Spectra Energy Corp
 
              
4
2

 
Marcel R. Coutu
 
 
Age 67
Calgary, Alberta, Canada
Independent
 
Director since
July 28, 2014
 
Latest date of retirement
May 2029
 
2020 annual meeting votes for: 89.05%
   
 
 
Mr. Coutu was the Chairman of Syncrude Canada Ltd. (integrated oil sands project) from 2003 to 2014 and was the President and Chief Executive Officer of Canadian Oil Sands Limited from 2001 until January 2014. From 1999 to 2001, he was Senior Vice President and Chief Financial Officer of Gulf Canada Resources Limited. Prior to 1999, Mr. Coutu held various executive positions with TransCanada PipeLines Limited and various positions in the areas of corporate finance, investment banking and mining and oil and gas exploration and development. Mr. Coutu holds an HBSc (Bachelor of Science, Honours Earth Science) from the University of Waterloo and an MBA (Master of Business Administration) from the University of Western Ontario.
 
 
 
 
Enbridge Board/Board committee memberships
 
     
 
2020 meeting
attendance
1
 
 
 
Board of Directors
     
5 out of 6
   
83%
 
 
Audit, Finance & Risk
     
5 out of 5
   
100%
 
 
Human Resources & Compensation
     
4 out of 4
   
100%
 
 
Total
 
 
    
14 out of 15
 
  
 
 
93%
 
 
 
 
 
Enbridge securities held
3
 
            
      
Enbridge
shares
  
DSUs
4
     
 
Total market value of
Enbridge shares & DSUs
5
  
Minimum
required
6
 
    
 
 
 
46,900
 
 
  
39,090
     
$3,805,069
   
$925,880
 
 
 
Other board/board committee memberships
7
 
            
 
 
Public
7
 
            
 
 
Brookfield Asset Management Inc.
(public global asset management company)
 
 
    
 
Director
Chair, audit committee
Member, management resources and compensation committee
 
 
 
 
 
 
Power Corporation of Canada
(public international management and holding company)
 
 
    
 
Director
Member, audit committee and human resources committee
 
 
 
 
 
The Great-West Lifeco Inc.
(public international financial services holding company that is an indirect subsidiary of Power Corporation of Canada)
 
 
    
 
Director
Member, governance and nominating committee, human resources committee and investment committee
 
 
 
 
 
IGM Financial Inc.
(public personal financial services company that is an indirect subsidiary of Power Corporation of Canada)
 
 
 
    
 
Director
Member, human resources committee
 
 
   
 
Not-for-profit
7
 
            
     
      
 
Calgary Stampede Foundation
 
     
Director
 
      

5

 
Susan M. Cunningham
 
 
Age 65
Houston, Texas, USA
Independent
 
Director since
February 13, 2019
 
Latest date of retirement
May 2031
 
2020 annual meeting votes for: 97.37%
   
 
 
Ms. Cunningham has been an Advisor for Darcy Partners (consulting firm) since 2017. From 2014 to 2017, Ms. Cunningham was Executive Vice President, EHSR (Environment, Health, Safety, Regulatory) and New Frontiers (global exploration, new ventures, geoscience and business innovation) at Noble Energy, Inc. From 2001 to 2013, she held various senior management roles with Noble Energy, Inc. Prior thereto, Ms. Cunningham held positions with Texaco U.S.A., Statoil Energy, Inc. and Amoco Corporation. Ms. Cunningham holds a BA in Geology and Geography from McMaster University and is a graduate of Rice University’s Executive Management Program. She was also Chairman of the OTC (Offshore Technology Conference) from 2010 to 2011.
 
 
 
 
Enbridge Board/Board committee memberships
 
     
 
2020 meeting
attendance
1
 
 
 
Board of Directors
     
6 out of 6
   
100%
 
 
Corporate Social Responsibility (Chair)
8
     
2 out of 2
   
100%
 
 
Human Resources & Compensation
     
4 out of 4
   
100%
 
 
Safety & Reliability
     
4 out of 4
   
100%
 
 
Total
 
 
    
16 out of 16
 
  
 
 
100%
 
 
 
 
 
Enbridge securities held
3
 
            
      
Enbridge
shares
   
DSUs
4
     
 
Total market value of
Enbridge shares & DSUs
5
  
Minimum
required
6
 
    
 
 
2,581
 
 
 
  
 
 
7,827
 
 
 
    
$460,564
 
  
 
 
$925,880
 
 
 
 
 
Other board/board committee memberships
7
 
            
 
 
Public
7
 
            
 
 
Oil Search Limited
(public oil and gas exploration and production)
 
 
    
 
Director
Member, audit and financial risk committee, sustainability committee and project and technology committee
 
 
 
 
 
Whiting Petroleum Corporation
(public oil and gas exploration and production)
 
 
    
 
Director
Chair, ESG committee
Member, audit committee
 
 
 
 
6

 
Gregory L. Ebel
 
 
Age 56
Houston, Texas, USA
Independent
 
Director since
February 27, 2017
 
Latest date of retirement
May 2039
 
2020 annual meeting votes for: 91.77%
   
 
 
Mr. Ebel served as Chairman, President and Chief Executive Officer of Spectra Energy Corp (“Spectra Energy”) from January 1, 2009 to February 27, 2017 at which time he became a Director of Enbridge and Chair of the Enbridge Board. Prior to that time, Mr. Ebel served as Spectra Energy’s Group Executive and Chief Financial Officer beginning in January 2007. He served as President of Union Gas Limited from January 2005 until January 2007, and Vice President, Investor & Shareholder Relations of Duke Energy Corporation from November 2002 until January 2005. Mr. Ebel joined Duke Energy in March 2002 as Managing Director of Mergers and Acquisitions in connection with Duke Energy’s acquisition of Westcoast Energy Inc. Mr. Ebel holds a BA (Bachelor of Arts, Honours) from York University and is a graduate of the Advanced Management Program at the Harvard Business School.
 
 
 
 
Enbridge Board/Board committee memberships
9
 
     
 
2020 meeting
attendance
1
 
 
 
Board of Directors (Chair)
     
6 out of 6
   
100%
 
 
Total
 
 
    
6 out of 6
 
  
 
 
100%
 
 
 
 
 
Enbridge securities held
3
 
            
      
Enbridge
shares
   
DSUs
4
   
Stock
Options
10
     
 
Total market value of
Enbridge shares & DSUs
(excluding stock options)
5
  
Minimum
required
6
 
   
 
 
651,845
 
 
 
  
 
 
32,217
 
 
 
  
 
 
405,408
 
 
 
    
$30,269,732
 
  
 
 
$925,880
 
 
 
 
 
Other board/board committee memberships
7
 
            
 
 
Public
7
 
            
 
 
The Mosaic Company
(public producer and marketer of concentrated phosphate and potash)
 
 
    
 
Chair of the Board
Member, audit committee and corporate governance and nominating committee
 
 
 
 
 
Baker Hughes Company
(public supplier of oilfield services and products)
 
 
    
 
Director
Chair, audit committee
Member, governance and corporate responsibility committee
 
 
 
 
 
 
Former
U.S.-listed
company directorships (last 5 years)
 
     
 
Spectra Energy Corp
 
              
7

 
J. Herb England
 
 
Age 74
Naples, Florida, USA
Independent
 
Director since
January 1, 2007
 
Latest date of retirement
May 2022
 
2020 annual meeting votes for: 96.74%
   
 
 
Mr. England has been Chair & Chief Executive Officer of Stahlman-England Irrigation Inc. (contracting company) in southwest Florida since 2000. From 1993 to 1997, Mr. England was the Chair, President & Chief Executive Officer of Sweet Ripe Drinks Ltd. (fruit beverage manufacturing company). Prior to 1993, Mr. England held various executive positions with John Labatt Limited (brewing company) and its operating companies, including the position of Chief Executive Officer of Labatt Brewing Company – Prairie Region (brewing company), Catelli Inc. (food manufacturing company) and Johanna Dairies Inc. (dairy company). In 1993, Mr. England retired as Senior Vice President, Finance and Corporate Development & Chief Financial Officer of John Labatt Limited. Mr. England holds a BA (Bachelor of Arts) from the Royal Military College of Canada and an MBA (Master of Business Administration) from York University. He also has a CA (Chartered Accountant) designation.
 
 
 
 
Enbridge Board/Board committee memberships
 
     
 
2020 meeting
attendance
1
 
 
 
Board of Directors
     
6 out of 6
   
100%
 
 
Audit, Finance & Risk
     
5 out of 5
   
100%
 
 
Corporate Social Responsibility
11
     
2 out of 2
   
100%
 
 
Governance
     
4 out of 4
   
100%
 
 
Total
 
 
    
17 out of 17
 
  
 
 
100%
 
 
 
 
 
Enbridge securities held
3
 
            
      
Enbridge
shares
   
DSUs
4
     
 
Total market value of
Enbridge shares & DSUs
5
  
Minimum
required
6
 
    
 
 
37,306
 
 
 
  
 
 
86,576
 
 
 
    
$5,481,792
 
  
 
 
$925,880
 
 
 
 
 
Other board/board committee memberships
7
 
            
 
 
Public
7
 
            
 
 
FuelCell Energy, Inc.
(public fuel cell company in which Enbridge holds a small interest)
 
 
    
 
Chair of the Board
Member, audit and finance committee and nominating and governance committee
 
 
 
 
 
Private
7
 
            
 
 
Stahlman - England Irrigation Inc.
(private contracting company)
 
 
    
 
Chair of the Board
Chief executive officer
 
 
 
   
 
USA Grading Inc.
(private excavating, grading and underground utilities company)
 
 
 
    
 
Director
 
    
    
 
Former
U.S.-listed
company directorships (last 5 years)
 
     
     
      
 
Enbridge Energy Management, LLC
 
              
8

 
Gregory J. Goff
 
 
Age 64
San Antonio, Texas, USA
Independent
 
Director since
February 11, 2020
 
Latest date of retirement
May 2032
 
2020 annual meeting votes for: 99.57%
   
 
 
Mr. Goff was Executive Vice Chairman of Marathon Petroleum Corporation from October 2018 until his retirement in December 2019. He was President and Chief Executive Officer of Andeavor (an integrated downstream energy company) from 2010 to 2018 and Chairman from December 2014 to 2018. Prior thereto, Mr. Goff held a number of senior leadership positions with ConocoPhillips Corporation (an oil and gas exploration and production company). Mr. Goff holds a B.S. (Bachelor of Science) and an MBA (Master of Business Administration) from the University of Utah.
 
 
 
 
Enbridge Board/Board committee memberships
 
     
 
2020 meeting
attendance
1
 
 
 
Board of Directors
 
    
6 out of 6
  
 
100%
 
 
Governance
12
 
    
2 out of 2
  
 
100%
 
 
Human Resources & Compensation
12
 
    
2 out of 2
  
 
100%
 
 
Total
 
 
    
10 out of 10
 
  
 
 
100%
 
 
 
 
 
Enbridge securities held
3
 
            
   
 
  
Enbridge
shares
   
DSUs
4
     
 
Total market value of
Enbridge shares & DSUs
5
  
Minimum
required
6
 
   
 
 
-
 
 
 
  
 
 
3,644
 
 
 
    
$161,230
 
  
 
 
$925,880
 
 
 
 
 
Other board/board committee memberships
7
 
            
 
 
Public
7
 
            
 
 
Avient Corporation (formerly PolyOne Corporation)
(public company producing specialty polymers)
 
 
    
 
Director
Chair, EHS committee
Member, governance and corporate responsibility committee
 
 
 
 
 
V. Maureen Kempston Darkes
 
 
Age 72
Toronto, Ontario, Canada
Lauderdale-by-the-Sea,
Florida, USA
Independent
 
Director since
November 2, 2010
 
Latest date of retirement
May 2024
 
2020 annual meeting votes for: 97.25%
   
 
 
 
Ms. Kempston Darkes is the retired Group Vice President and President Latin America, Africa and Middle East, General Motors Corporation (automotive corporation and vehicle manufacturer). From 1994 to 2001, she was the President and General Manager of General Motors of Canada Limited and Vice President of General Motors Corporation. Ms. Kempston Darkes holds a BA (Bachelor of Arts) and an LLB (Bachelor of Laws), both from the University of Toronto.
 
 
 
 
Enbridge Board/Board committee memberships
 
     
 
2020 meeting
attendance
1
 
 
 
Board of Directors
 
    
6 out of 6
  
 
100%
 
 
Corporate Social Responsibility
13
 
    
2 out of 2
  
 
100%
 
 
Human Resources & Compensation (Chair)
 
    
4 out of 4
  
 
100%
 
 
Safety & Reliability
 
    
4 out of 4
  
 
100%
 
 
Total
 
 
    
16 out of 16
 
  
 
 
100%
 
 
 
 
 
Enbridge securities held
3
 
            
   
 
  
Enbridge
shares
   
DSUs
4
     
 
Total market value of
Enbridge shares & DSUs
5
  
Minimum
required
6
 
   
 
 
21,735
 
 
 
  
 
 
57,789
 
 
 
    
$3,518,945
 
  
 
 
$925,880
 
 
 
 
 
Other board/board committee memberships
7
 
            
 
 
Public
7
 
            
  
 
Brookfield Asset Management Inc.
(public global asset management company)
 
 
    
 
Director
Chair, risk management committee
Member, management resources and compensation committee
 
 
 
 
  
 
Canadian National Railway Company
14
(public railway company)
 
 
    
 
Director
Chair, strategic planning committee
Member, audit committee, finance committee and pension and investment committee
 
 
 
 
   
 
Former
U.S.-listed
company directorships (last 5 years)
 
     
  
 
 
 
Schlumberger Limited
 
       
 
    
 
 
9

 
Teresa S. Madden
 
 
Age 65
Boulder, Colorado, USA
Independent
 
Director since
February 12, 2019
 
Latest date of retirement
May 2031
 
2020 annual meeting votes for: 98.59%
 
 
 
 
 
 
Ms. Madden was the Executive Vice President and Chief Financial Officer of Xcel Energy, Inc., an electric and natural gas utility, from 2011 until her retirement in 2016. She joined Xcel in 2003 as Vice President, Finance, Customer & Field Operations and was named Vice President and Controller in 2004. Prior thereto, Ms. Madden held positions with Rogue Wave Software, Inc. as well as New Century Energies and Public Service Company of Colorado, predecessor companies of Xcel Energy. Ms. Madden holds a BS (Bachelor of Science) in Accounting from Colorado State University and an MBA (Master of Business Administration) from Regis University.
 
 
 
 
Enbridge Board/Board committee memberships
 
     
 
2020 meeting
attendance
1
 
 
 
 
Board of Directors
 
    
 
6 out of 6
  
 
 
 
100%
 
 
 Audit, Finance & Risk (Chair)
 
    5 out of 5   100% 
 Governance
 
    4 out of 4   100% 
 
Total
 
 
    
15 out of 15
 
  
 
 
100%
 
 
 
 
 
Enbridge securities held
3
 
            
   
 
  
 
Enbridge
shares
  
DSUs
4
     
Total market value of
Enbridge shares & DSUs
5
  
Minimum
required
6
 
    
 
 
 
1,000
 
 
  7,934     
$395,338
   $925,880 
   
 
Other board/board committee memberships
7
 
            
   
 
Public
7
 
            
  
 
The Cooper Companies, Inc.
(public medical device company)
 
 
 
    
 
Director
Member, audit committee
 
 
 
  
 
 
 
Former
U.S.-listed
company directorships (last 5 years)
 
    
 
 
  
 
 
 
Peabody Energy Corp.
 
       
 
    
 
 
10

 
Al Monaco
 
 
Age 61
Calgary, Alberta, Canada
Not Independent
 
Director since
February 27, 2012
 
Latest date of retirement
May 2035
 
2020 annual meeting votes for: 97.99%
 
 
 
 
 
 
Mr. Monaco joined Enbridge in 1995 and has held increasingly senior positions. He has been President & Chief Executive Officer of Enbridge since October 1, 2012 and served as Director and President of Enbridge from February 27, 2012 to September 30, 2012. Mr. Monaco holds an MBA (Master of Business Administration) from the University of Calgary and has a Chartered Professional Accountant designation.
 
 
 
 
Enbridge Board/Board committee memberships
15
 
     
 
2020 meeting
attendance
1
 
 
 
 
Board of Directors
 
 
    
 
6 out of 6
 
  
 
 
 
 
100%
 
 
 
 
 
 
Enbridge securities held
3
 
            
      
 
Enbridge
shares
  
Stock
Options
     
 
Total market value of
Enbridge shares
(excluding stock options)
5
  
Minimum
required
16
 
   
 
 
 
920,699
 
 
  4,465,600     
$40,740,931
   N/A 
 
 
Other board/board committee memberships
7
 
     
 
 
Public
7
 
            
  
 
Weyerhaeuser Company
(public timberlands company and wood products manufacturer)
 
 
 
    
 
Director
Member, compensation committee
 
 
 
   
 
Private
7
 
            
  
 
DCP Midstream, LLC
(a private 50/50 joint venture between Enbridge and Phillips 66 and the general partner of DCP Midstream GP, LLC, the general partner of DCP Midstream GP, LP, the general partner of DCP Midstream Partners, LP, a midstream master limited partnership with public unitholders)
 
 
 
    
 
Director
Member, human resources and compensation committee
 
 
 
    
 
Not-for-profit
7
 
            
  
 
American Petroleum Institute
(not-for-profit
trade association)
 
 
 
    
 
Director
Member, executive committee and finance committee
 
 
 
  
 
Business Council of Canada
(not-for-profit,
non-partisan
organization composed of CEOs of Canada’s leading enterprises)
 
 
 
    
 
Member
 
 
  
 
Business Council of Alberta
 
 
    
 
Member
 
 
  
 
U.S. National Petroleum Council
 
 
    
 
Member
 
 
  
 
Catalyst Canada Advisory Board
 
 
    
 
Member
 
 
11

 
Stephen S. Poloz
 
 
Age 65
Ottawa, Ontario, Canada
Independent
 
Director since
June 4, 2020
 
Latest date of retirement
May 2031
 
    
 
 
Mr. Poloz was Governor of the Bank of Canada from June 3, 2013 until completion of his seven-year term on June 2, 2020. He also served as Chairman for the Board of Directors of the Bank and a member of the Board of Directors of the Bank for International Settlements (BIS). Mr. Poloz held a number of senior positions with the Bank prior thereto. Mr. Poloz served as managing editor of The International Bank Credit Analyst, the flagship publication of BCA Research and is the former President & Chief Executive Officer of Export Development Canada. Mr. Poloz holds a BA (Bachelor of Arts) (Honours) from Queen’s University and MA (Master of Arts) (Economics) and PhD (Doctor of Philosophy) (Economics), both from the University of Western Ontario. He is a Certified International Trade Professional and a graduate of Columbia University’s Senior Executive Program.
 
 
 
 
Enbridge Board/Board committee memberships
 
     
 
2020 meeting
attendance
1
 
 
 
 
Board of Directors
17
 
    
 
3 out of 3
  
 
 
 
100%
 
 
 
Audit, Finance & Risk
17
     2 out of 2   100% 
 
Safety & Reliability
17
     1 out of 1   100% 
 
Total
 
 
    
6 out of 6
 
  
 
 
100%
 
 
 
 
 
Enbridge securities held
3
 
            
      
 
Enbridge
shares
  
DSUs
4
     
Total market value of
Enbridge shares & DSUs
5
  
Minimum
required
6
 
    
 
 
 
-
 
 
  2,676     
$118,398
   $925,880 
   
 
Other board/board committee memberships
7
 
            
   
 
Public
7
 
            
  
 
CGI Inc.
(public IT and business consulting services company)
 
 
 
    
 
Director
Member, audit and risk management committee
 
 
 
12

 
Dan C. Tutcher
 
 
Age 72
Houston, Texas, USA
Independent
 
Director since
May 3, 2006
 
Latest date of retirement
May 2024
 
2020 annual meeting votes for: 97.81%
    
 
 
Mr. Tutcher is on the Board of Directors of Gulf Capital Bank, where he is Chairman of Governance Committee. Mr. Tutcher was Managing Director, Public Securities on the Energy Infrastructure Equities team for Brookfield’s Public Securities Group from October 2018 until February 2021. Prior to joining Brookfield in 2018, Mr. Tutcher was President & Chair of the Board of Trustees of Center Coast MLP & Infrastructure Fund since 2013 and a Principal in Center Coast Capital Advisors L.P. since its inception in 2007. He was the Group Vice President, Transportation South of Enbridge, as well as President of Enbridge Energy Company, Inc. (general partner of former Enbridge sponsored affiliate Enbridge Energy Partners, L.P.) and Enbridge Energy Management, L.L.C. (another former Enbridge sponsored vehicle) from May 2001 until May 1, 2006. From 1992 to May 2001, he was the Chair of the Board of Directors, President & Chief Executive Officer of Midcoast Energy Resources, Inc. Mr. Tutcher holds a BBA (Bachelor of Business Administration) from Washburn University.
 
 
 
 
Enbridge Board/Board committee memberships
 
     
 
2020 meeting
attendance
1
 
 
 
 
Board of Directors
 
    
 
6 out of 6
  
 
 
 
100%
 
 
 Corporate Social Responsibility     3 out of 4   75% 
 Safety & Reliability (Chair)     3 out of 4   75% 
 
Total
 
 
    
12 out of 14
 
  
 
 
86%
 
 
 
 
 
Enbridge securities held
3
 
            
      
 
Enbridge
shares
  
DSUs
4
     
Total market value of
Enbridge shares & DSUs
5
  
Minimum
required
6
 
    
 
 
 
637,523
 
 
  138,662     
 
$34,346,186
   $925,880 
   
 
Other board/board committee memberships
7
 
            
   
 
Private
7
 
            
  
 
Gulf Capital Bank
 
 
    
 
Director
Chair, governance committee
 
 
 
    
 
Former
U.S.-listed
company directorships (last 5 years)
 
      
    
 
Center Coast MLP & Infrastructure Fund
 
              
1
Percentages are rounded to the nearest whole number.
2
Ms. Carter was appointed to the Human Resources & Compensation Committee on May 4, 2020.
3
Information about beneficial ownership and about securities controlled or directed was provided by the director nominees and is as at March 2, 2021.
4
DSUs refer to deferred share units and are defined on page 59 of this Amendment No. 1 on Form 10-K/A.
5
Total market value = number of common shares or deferred share units × closing price of Enbridge shares on the TSX on March 2, 2021 of $44.25, rounded to the nearest dollar.
6
Directors must hold at least three times their annual US$242,250 Board retainer in DSUs or Enbridge shares within five years of becoming a director on our Board. Amounts are converted to C$ using US$1 = C$1.2740, the published WM/Reuters 4 pm London exchange rate for December 31, 2020. All director nominees meet or exceed this requirement except Mses. Madden and Cunningham, who have until February 12, 2024 and February 13, 2024, respectively, Mr. Goff, who has until February 11, 2025, and Mr. Poloz, who has until June 4, 2025, to meet this requirement.
7
Public
means a corporation or trust that is a reporting issuer in Canada, a registrant in the U.S., or both, and that has publicly listed equity securities.
Private
means a corporation or trust that is not a reporting issuer or registrant.
Not
-for
-profit
means a corporation, society or other entity organized for a charitable, civil or other social purpose which does not generate profits for its members.
8
Ms. Cunningham was appointed to the Corporate Social Responsibility Committee on May 4, 2020.
9
Mr. Ebel is not a member of any Board committee, but as Chair of the Board he attends their meetings.
10
Mr. Ebel’s stock options were Spectra Energy options that converted into options to purchase Enbridge shares upon the closing of the Merger Transaction (as defined on page 67). No new Enbridge stock options were granted to Mr. Ebel in his capacity as a Director of Enbridge or Chair of the Enbridge Board.
11
Mr. England was appointed to the Corporate Social Responsibility Committee on May 4, 2020.
12
Mr. Goff was appointed to the Governance Committee and the Human Resources & Compensation Committee on May 4, 2020.
13
Ms. Kempston Darkes ceased being a member of the Corporate Social Responsibility Committee on May 4, 2020.
14
Ms. Kempston Darkes is not standing for re-election to the Canadian National Railway Company board and will retire from that board in April 2021.
15
Mr. Monaco is not a member of any Board committee, but as President & CEO he attends their meetings at the request of such committees.
16
As President & CEO, Mr. Monaco is required to hold Enbridge shares equal to six times his base salary (see page 44). Mr. Monaco is not required to hold Enbridge shares as a director.
17
Mr. Poloz was appointed to the Board on June 4, 2020. He was appointed to Audit, Finance & Risk Committee and the Safety & Reliability Committee on July 22, 2020.
13

Director independence
  Name
Independent
Not independent
Reason for non-independence
  Gregory L. Ebel (Chair)
  Pamela L. Carter
  Marcel R. Coutu
  Susan M. Cunningham
  J. Herb England
  Gregory J. Goff
  V. Maureen Kempston Darkes
  Teresa S. Madden
  Al Monaco (President & CEO)
President & CEO of the company
  Stephen S. Poloz
  Dan. C. Tutcher
Current Board committee participation
  Director
Audit,
Finance &
Risk
Committee
Corporate
Social
Responsibility
Committee
Governance
Committee
Human
Resources &
Compensation
Committee
Safety &
Reliability
Committee
Not Independent
  Al Monaco
1
(President & CEO)
Independent
  Pamela L. Carter
chair
  Marcel R. Coutu
2
  Susan M. Cunningham
3
chair
  Gregory L. Ebel
1
(Chair)
  J. Herb England
2
  Gregory J. Goff
  V. Maureen Kempston Darkes
4
chair
  Teresa S. Madden
2, 5
chair
  Stephen S. Poloz
  Dan C. Tutcher
6
chair
1
Messrs. Monaco and Ebel are not members of any of the committees of the Board. They attend committee meetings in their capacities as President & CEO and Chair of the Board, respectively.
2
Ms. Madden and Messrs. Coutu and England each qualify as an audit committee financial expert, as defined under the
U.S. Securities Exchange Act of 1934
,
as amended. The Board has also determined that all members of the Audit, Finance & Risk Committee are financially literate according to the meaning of National Instrument
52-110
Audit Committees
and the rules of the NYSE.
3
Ms. Cunningham was appointed as Chair of the Corporate Social Responsibility Committee on May 4, 2020.
4
Ms. Kempston Darkes was appointed as Chair of the Human Resources & Compensation Committee on May 4, 2020.
5
Ms. Madden was appointed Chair of the Audit, Finance & Risk Committee on May 4, 2020.
6
Mr. Tutcher was appointed Chair of the Safety & Reliability Committee on July 22, 2020.
14

Mix of skills and experience
We maintain a skills and experience matrix for our directors in areas we think are important for a corporation like ours. We use this skills matrix to annually assess our Board composition and in the recruitment of new directors. The table below indicates each director’s skills and experience in the areas indicated based on a self-assessment by each director.
  Area
  Carter
  Coutu
  Cunningham
  Ebel
  England
  Goff
  Kempston
  Darkes
  Madden
  Monaco
  Poloz
  Tutcher
  Managing and Leading Strategy and Growth
  International
  CEO / CFO / Executive Officer
  Governance / Board
  Operations (Oil & Gas / Energy)
  Risk Oversight / Management
  Corporate Social Responsibility & Sustainability
  Energy Marketing
  Human Resources / Compensation
  Investment Banking / Mergers and Acquisitions
  Financial Literacy
  Information Technology
  Health, Safety & Environment
  Public Policy and Government and Stakeholder Relations
  Emerging Sectors / Growth Opportunities
15

EXECUTIVE OFFICERS OF REGISTRANT
The information regarding executive officers is included in
Part I.
Item 1. Business - Executive Officers
of the Original Filing.
CORPORATE GOVERNANCE
Enbridge is a “foreign private issuer” pursuant to applicable U.S. securities laws. Accordingly, Enbridge is permitted to follow home country practice instead of certain governance requirements set out in the New York Stock Exchange (the “NYSE”) rules, provided we disclose any significant differences between our governance practices and those required by the NYSE. Further information regarding those differences is available on our website (www.enbridge.com).
We have a comprehensive system of stewardship and accountability that meets applicable Canadian and U.S. requirements, including:
Canadian Securities Administrators National Policy
58-201 –
Corporate Governance Guidelines
, National Instrument
58-101
– Disclosure of Corporate Governance Practices
and National Instrument
52-110
Audit Committees
;
requirements of the CBCA; and
the corporate governance guidelines of the NYSE.
STATEMENT ON BUSINESS CONDUCT
Our Statement on Business Conduct (available on our website at www.enbridge.com) is our formal statement of expectations that applies to all individuals at Enbridge and our subsidiaries, including our directors, officers, employees, contingent workers as well as consultants and contractors retained by Enbridge. It discusses what we expect in various areas including:
complying with the law, applicable rules and all policies;
avoiding conflicts of interest, including examples of acceptable forms of gifts and entertainment;
anti-corruption and money laundering;
acquiring, using and maintaining assets (including computers and communication devices) appropriately;
data privacy, records management, and proprietary, confidential and insider information;
protecting health, safety and the environment;
interacting with landowners, customers, shareholders, employees and others; and
respectful workplace/no harassment.
The Board approved a revised Statement on Business Conduct in 2017, which became effective on September 29, 2017.
On the commencement of employment with Enbridge and annually thereafter, all Enbridge employees and contingent workers active in the company’s human resources information system are required to complete Statement on Business Conduct training and certify compliance with the Statement on Business Conduct. In addition, employees and contingent workers are also required to disclose any actual or potential conflicts of interest.
Directors must also certify their compliance with the Statement on Business Conduct on an annual basis.
During January 2021, all employees and contingent workers active in the company’s human resources information system were required to complete online Statement on Business Conduct training, certify their compliance and declare any real or potential conflicts of interest. As of the date of the Circular, approximately 99.2% of these Enbridge employees and contingent workers had certified compliance with the Statement on Business Conduct for the year ended December 31, 2020. All 11 current directors on the Board have also certified their compliance with the Statement on Business Conduct for the year ended December 31, 2020.
AUDIT, FINANCE & RISK COMMITTEE
The Audit, Finance & Risk Committee fulfills public company audit committee obligations and assists the Board with oversight of: the integrity of the company’s financial statements; the company’s compliance with legal and regulatory requirements; the independent auditor’s qualifications and independence; and the performance of the company’s internal audit function and external auditors. The committee also assists the Board with the company’s risk identification, assessment and management program.
Financial literacy
The Board defines an individual as financially literate if he or she can read and understand financial statements that are generally comparable to ours in breadth and complexity of issues. The Board has determined that all of the members of the Audit, Finance & Risk Committee are financially literate according to the meaning of NI
52-110
and the rules of the NYSE. It has also determined that Ms. Madden and Messrs. Coutu and England each qualify as “audit committee financial experts” as defined by the Exchange Act. The Board bases this determination on each director’s education, skills and experience.
16

ITEM 11. EXECUTIVE COMPENSATION
As a foreign private issuer in the United States, we are deemed to comply with this Item if we provide information required by Items 6.B and 6.E.2 of Form
20-F,
with more detailed information provided if otherwise made publicly available or required to be disclosed in Canada. We have provided information required by Items 6.B and 6.E.2 of Form
20-F
in the Circular. As a foreign private issuer in the United States we are not required to disclose executive compensation according to the requirements of Regulation
S-K
that apply to U.S. domestic issuers, and we are not otherwise required to adhere to the U.S. requirements relative to certain other proxy disclosures and requirements. Our executive compensation disclosure complies with Canadian requirements, which are, in many respects, substantially similar to U.S. rules.
Compensation committee interlocks and insider participation
The table below sets out the board interlocks in 2020. The Board has determined that the board interlocks set out below do not impair the ability of these directors to exercise independent judgment as members of our Board.
  Name
Serve together on this board of a
public company
Serve on these committees
Marcel R. Coutu
Brookfield Asset Management Inc.
Chair, audit committee
Member, management resources and compensation committee
V. Maureen Kempston Darkes
Chair, risk management committee
Member, management resources and compensation committee
17

Compensation discussion and analysis
Executive compensation
The following compensation discussion and analysis describes the 2020 compensation programs for our Named Executive Officers (“NEOs”). For 2020, our NEOs
were:
Al Monaco
President & Chief Executive Officer (CEO)
Colin K. Gruending
Executive Vice President & Chief Financial Officer (CFO)
John K. Whelen
1
Former Executive Vice President
William T. Yardley
Executive Vice President & President, Gas Transmission & Midstream
Vern D. Yu
Executive Vice President & President, Liquids Pipelines
Robert R. Rooney
Executive Vice President & Chief Legal Officer (CLO)
Mr. Whelen retired effective November 15, 2020.
18

Executive summary
Strategic focus
Our 2020 Strategic Plan continued to emphasize disciplined organic growth of our four blue chip franchises: Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage and Renewable Power Generation. Our strategic priorities are focused on driving growth through the enhancement of existing asset returns, along with prudent investment in new
in-franchise
and capital efficient organic growth projects that fit our low risk pipeline-utility model. At the foundation of our strategic plan is a continued focus on the safe and reliable transportation of energy to end use markets, which is always our number one priority.
We delivered strong results driven by solid operating performance across the entire asset base despite the unprecedented impact of
COVID-19,
demonstrating the resiliency of cashflows associated with Enbridge’s
low-risk
business model.
Compensation philosophy
Our executive compensation design is grounded in a
pay-for-performance
philosophy. Accordingly, base salary is the sole fixed source of our NEOs’ total direct compensation and variable compensation amounts earned by our NEOs are strongly aligned to the achievement of Enbridge’s strategic priorities. Compensation is targeted at median within the markets where Enbridge competes, with performance driving “at risk” incentive payouts up or down accordingly. The vast majority of executive compensation is considered “at risk” because its value is based on specific performance criteria and/or share price and payout is not guaranteed.
Exemplifying our values
Enbridge’s overall response to the pandemic exemplified our values and focus on our people, the communities in which we operate and our shareholders.
The
COVID-19
crisis has taken an unprecedented human and economic toll. As a company that employs thousands of people across hundreds of communities, and that safely delivers affordable, reliable energy that fuels quality of life for millions, we take our responsibility to be resilient in the service of our shareholders seriously.
From the outset of the pandemic, Enbridge’s priority has been to protect its employees, their families and communities, while continuing to safely operate essential infrastructure that delivers the energy people rely on every day.
Management acted swiftly and with compassion to support our employees. This included immediately implementing a work-from-home policy wherever possible and new safety protocols to protect our people, keeping our systems running safely and maintaining work on critical projects. Our emergency childcare benefit was doubled, our compassionate care benefits were enhanced, and our mental health program was significantly expanded to ensure our people had the support they needed to cope with balancing personal and work responsibilities.
Performance highlights for 2020
Priorities
Actions
1
Delivered distributable cash flow (“DCF”) and dividend growth
•  Strong financial and operating performance
•  Delivered $4.67 DCF per share
1
, above the midpoint of the 2020 guidance range
•  Increased dividend for the 25th consecutive year
•  Achieved $300 million of cost savings
2
Advanced and extended secured growth program
•  Completed $1.6 billion of secured growth projects in 2020
•  Added $5 billion of planned gas pipeline modernization and utility growth capital projects to secured growth inventory through 2023
•  Reached final investment decisions on 500 MW Fécamp offshore wind farm
•  Completed construction of the U.S. portion of Line 3 Replacement Program in North Dakota and commenced construction on the final segment in Minnesota
•  Advanced development and construction on $16 billion of capital to be placed into service between 2021 and 2023
3
Maintained balance sheet strength and flexibility
•  Exited 2020 with 4.6x
Debt-to-EBITDA
•  Maintained industry-leading investment grade credit ratings
•  Added $3 billion of available liquidity
•  Sold $400 million in assets, further strengthening financial flexibility
4
Advanced strategic priorities
•  Advanced Mainline Contracting offering process with the Canada Energy Regulator
•  Completed rate proceedings on Texas Eastern, Algonquin and B.C. Pipeline systems
•  Realized synergy capture within Gas Distribution and Storage
1
DCF per share is a
non-GAAP
measure; this measure is defined and reconciled in Item 11 –
“Non-GAAP
reconciliation”.
19

Compensation highlights for 2020
The following table shows annual base salary increases, voluntary base salary reductions and awards under the short-, medium- and long-term incentive plans for the NEOs, in each case as a percentage of base salary:
Executive
  
Annual base
salary
increase
1
   
Base salary
reduction
2
   
Short-term

incentive
payment
   
Medium-term

incentive
award
   
Long-term

incentive
award
 
Al Monaco
   5%    -15%    207%    520%    130% 
Colin K. Gruending
   
25%
3
    -10%    130%    320%    80% 
John K. Whelen
   3%    -10%    127%    320%    80% 
William T. Yardley
   3%    -10%    121%    320%    80% 
Vern D. Yu
   
20%
3
    -10%    114%    320%    80% 
Robert R. Rooney
   5%    -10%    114%    280%    70% 
1
Annual base salary increases were effective April 1, 2020.
2
In response to the
COVID-19
pandemic, reduced energy demand and reduced commodity prices, the CEO implemented voluntary base salary reductions, effective June 1, 2020.
3
Mr. Gruending and Mr. Yu each received a base salary increase to better align their positioning relative to the competitive market, as part of a
phased-in
approach since their role changes in 2019.
20

Compensation policies and practices
What we do
What we don’t do
 Use a
pay-for-performance
philosophy whereby the majority of compensation provided to executives is “at risk”
×
  Pay out incentive awards when unwarranted by performance
 Use a blend of short-, medium- and long-term incentive awards that are linked to business plans for the respective timeframe
×
  Count performance stock units, unvested restricted stock units or unexercised stock options toward stock ownership requirements
 Incorporate risk management principles into all decision-making processes to ensure compensation programs do not encourage inappropriate or excessive risk-taking by executives
×
  Grant stock options with exercise prices below 100% fair market value or
re-price
out-of-the-money
options
 Regularly review executive compensation programs through third-party experts to ensure ongoing alignment with shareholders and regulatory compliance
×
  Use employment agreements with single-trigger voluntary termination rights in favor of executives
 Use both preventative and incident-based safety, environmental and operational metrics that are directly linked to short-term incentive awards
×
  Permit hedging of Enbridge securities
 Have meaningful stock ownership requirements that align the interests of executives with those of Enbridge shareholders
×
  Grant loans to directors or senior executives
 Benchmark executive compensation programs against a group of similar companies in Canada and the U.S. to ensure that executives are rewarded at competitive levels
×
  Provide stock options to
non-employee
directors
 Have an incentive compensation clawback policy
×
  Guarantee bonuses
 Use double-trigger
change-in-control
provisions within all incentive plan agreements beginning in 2017
×
  Apply tax
gross-ups
to awards
21

Assessing 2020 performance
As always, Enbridge’s focus on the safety of its employees, their families and their communities was at the forefront of our corporate actions in response to the
COVID-19
pandemic. Our response was swift and compassionate, supporting our employees and our operations. This included implementing an immediate work-from-home policy wherever possible and new safety protocols to protect our people, keeping our systems running safely and maintaining work on critical projects.
The following tables and charts outline key performance achievements for 2020.
Corporate actions
Delivered strong financial results
Optimized the base business
•  Achieved DCF per share
1
above the midpoint of guidance range
•  Solid operational performance across all business lines
•  4.6x
Debt-to-EBITDA
•  Achieved $300 million in cost savings
•  Completed rate proceedings on Texas Eastern, Algonquin and B.C. Pipeline
•  Captured synergies through amalgamated utilities
Growing organically
Executed capital program
•  Added approximately $5 billion of growth capital to the secured growth inventory in 2020
•  Completed construction of the U.S. portion of Line 3 Replacement Program in North Dakota and commenced construction on the final segment in Minnesota
•  Completed $1.6 billion of secured growth projects, including the final phase of Atlantic Bridge, Sabal Trail Phase II, the 2020 Modernization Program within Gas Transmission and Midstream, and the 2020 Utility Growth Program, including the Owen Sound Reinforcement and Windsor Line Replacement projects
1
DCF per share is a
non-GAAP
measure; this measure is defined and reconciled in Item 11 –
“Non-GAAP
reconciliation”.
2020 project execution
Page
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Expected ISD56
Capital ($B)
1
Item 6.
Item 7.Sabal Trail Phase II
In-service58
US$0.1
2020 Modernization ProgramItem 7A.US$0.7
Item 8.
Item 9.2020 Utility Growth Program
In-service179
0.5
Item 9A.
2020 Total
Item 9B.
1.6
Item 9C.
U.S. dollars have been converted to Canadian dollars using an exchange rateDisclosure Regarding Foreign Jurisdictions that Prevent Inspections
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
Item 16.
Signatures
Financial
DCF per share
1

1
DCF and DCF per share are
non-GAAP
measures; these measures are defined and reconciled in Item 11 –
“Non-GAAP
reconciliation”.
22
3

Approach to executive compensation

Enbridge’s approach to executive compensation is set by the Human Resources & Compensation (“HRC”) Committee and approved by the Board. The compensation programs are designed to accomplish three objectives:
attract and retain a highly effective executive team;
align executives’ actions with Enbridge’s business strategy and the interests of Enbridge shareholders and other stakeholders; and
incentivize and reward executives for short-, medium- and long-term performance.
Alignment with company strategy
Safety and operational reliability is Enbridge’s number one priority.
Enbridge’s vision is to be the leading energy delivery company in North America. To achieve this goal, we are committed to delivering the energy people need and want, and creating value for all stakeholders. We aim to be the first choice of our customers, attract and retain energized employees and maintain the trust of our stakeholders.
Central to achieving this vision is a relentless focus on safety, operational reliability and protection of the environment to ensure that the needs of all stakeholders are met, and that Enbridge continues to be a good citizen within the communities in which we live and operate.
Enbridge’s executive compensation programs are aligned with the achievement of our strategic priorities and are designed to link payouts to those outcomes. They motivate management to deliver exceptional value to Enbridge stakeholders through strong corporate performance and investing capital in ways that minimize risk and maximize return, while always supporting the core business goal of delivering energy safely and reliably.
Management is committed to delivering steady, visible and predictable results, and operating assets in an ethical and responsible manner.
Executive compensation design
Enbridge’s executive compensation design consists of several components that balance the use of short- (annual incentive), medium- (performance stock units and restricted stock units) and long-term vehicles (stock options). The following chart describes the NEOs’ compensation components and the time horizon for vesting and/or realized value.

23

Pay for performance
Performance is foundational to Enbridge’s executive compensation design; incentive compensation plans incorporate operational safety and financial performance conditions.
Performance is the cornerstone of Enbridge’s executive compensation design. The Board reviews Enbridge’s business plans over the short-, medium- and long-term and the HRC Committee ensures the compensation programs are linked to these time frames. This focuses management on delivering value to Enbridge shareholders not only in the short term, but also continued performance over the long term.
Relevant corporate and business unit performance measures are established for the short-term incentive plan (“STIP”) that focus on the critical safety, reliability, environmental, customer, employee and financial aspects of the business.
The performance measures for the medium- and long-term incentive plans focus on overall corporate performance aligned with Enbridge shareholder expectations for cash flow growth and total shareholder return.
When assessing performance, the HRC Committee considers performance results in the context of other qualitative factors not captured in the formal metrics, including key performance indicators relative to peers and the qualitative aspects of management’s responsibilities.
At risk compensation
The vast majority of compensation for Enbridge’s President & CEO and other NEOs is considered
“at risk”.
The chart below shows the target compensation mix for the President & CEO and the average for the other NEOs. The short-, medium- and long-term incentives are “at risk” because their value is based on specific performance criteria and payout is not guaranteed.
In 2020, 89% of the target total direct compensation for the President & CEO, and an average of 83% for the other NEOs, was at risk, directly aligning corporate, business unit and individual performance with the interests of Enbridge shareholders.

2020 compensation decisions
Base salary
Effective April 1, 2020, annual base salary adjustments, as shown below, were provided to the President & CEO and other NEOs. Mr. Gruending and Mr. Yu each received a base salary increase to better align their positioning relative to the competitive market, as part of a
phased-in
approach since their role changes in 2019.
While Enbridge demonstrated resilience throughout the crises in 2020, it was not immune to the precipitous decline in economic activity and reduced demand for energy. Management took prudent and necessary action to reduce operating costs across the business and avoided company-wide layoffs by pursuing initiatives including organization-wide salary rollbacks (with voluntary base salary reductions for the CEO (15%) and other NEOs (10%) and Board compensation reduction (15%) effective June 1, 2020), a voluntary workforce reduction program and supply chain efficiencies.
  Executive
 
Base salary
at January 1,
2020
1
  
April 1, 2020
increase %
  
Base salary
at April 1,
2020
1
  
June 1, 2020
reduction %
  
Base salary
at December 31,
2020
1
  
Total %
change in
base salary
in 2020
 
       
  Al Monaco
 $1,630,000   5%  $1,712,000   -15%  $1,455,200   -11% 
       
  Colin K. Gruending
 $525,000   25%  $656,300   -10%  $590,670   13% 
       
  John K. Whelen
 $641,200   3%  $660,400   -10%  $594,360   -7% 
       
  William T. Yardley
 $725,290   3%  $747,075   -10%  $672,367   -7% 
       
  Vern D. Yu
 $569,300   20%  $683,200   -10%  $614,880   8% 
       
  Robert R. Rooney
 $569,300   5%  $597,800   -10%  $538,020   -5% 
1
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
24

Short-term incentive
It is critically important to ensure all Enbridge executives are incentivized to achieve not only financial results but also operational results in areas such as safety and environmental performance. For this reason, our STIP awards are designed to be a comprehensive analysis of corporate, business unit and individual performance, as determined by our HRC Committee.
Corporate performance.
The corporate component of the performance metrics is based on a single, objective company-wide performance metric that is designed to drive achievement of near-term business priorities and financial results for the organization.
Business unit performance.
Business unit performance is assessed relative to a scorecard of metrics and targets established for each business and their senior management teams, as applicable to those objectives relating to the business unit.
Individual performance.
Individual performance metrics for each of our NEOs are established to align with financial, strategic and operational priorities related to each executive’s portfolio and their contributions to the overall organization in consultation with the President & CEO, in order to recognize and differentiate individual actions and contributions in final pay decisions.
Performance metrics and ranges for threshold, target and maximum incentive opportunities for the corporate component of the STIP award are determined by the HRC Committee at the beginning of the year. Each executive’s target award and payout range reflect the level of responsibility associated with their role, as well as competitive practice, and is established as a percentage of base salary. In 2020, the STIP targets were adjusted as part of a
phased-in
approach to align overall compensation to the competitive market, recognizing the increasing complexity of the business.
For 2020, each NEO’s target STIP award and corresponding weighting of corporate, business unit and individual performance metrics were as follows:
  Executive
  
2020 target
STIP (% of
base salary)
  
2020 target
STIP
1 2
  
Performance Measure Weighting
  
2019 target
STIP (% of
base salary)
 
 
Corporate
  
Business
Unit
  
Individual
 
       
  Al Monaco
   145 $2,241,900   60  20  20  
140
%
 
       
  Colin K. Gruending
   90 $528,370   60  20  20  
80
%
 
       
  John K. Whelen
3
   90 $488,240   60  20  20  
80
%
 
       
  William T. Yardley
   90 $630,020   40  40  20  
80
%
 
       
  Vern D. Yu
   90 $555,120   40  40  20  
80
%
 
       
  Robert R. Rooney
   80 $445,920   60  20  20  
75
%
 
1
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
2
2020 target STIP awards are based on base salary earned in 2020.
3
Mr. Whelen’s 2020 target STIP award has been prorated based on his retirement date of November 15, 2020.
The HRC Committee retains discretion to change performance measures, scorecards and the award levels when it believes it is reasonable to do so, considering matters such as key performance indicators and the business environment in which the performance was achieved. In addition, the HRC Committee retains discretion to approve adjustments to the calculated STIP award to reflect extraordinary events and other factors not contemplated in the original measures or targets. In 2020, no such adjustments were made to performance measures, scorecards or award levels, despite the unprecedented challenges Enbridge faced due to the
COVID-19
pandemic and the reduced energy demand.
As illustrated below, STIP awards are earned between
0-200%
of the target award based on achievement of the applicable corporate, business unit and individual performance metrics and giving effect to the applicable weighting of each metric.
25

Corporate performance
The corporate performance component is reviewed annually to select measures that align with our strategy and are appropriate for measuring annual performance. The same corporate component metrics and goals apply to each NEO. In February 2020, the HRC Committee approved management’s recommendation to use DCF per share. The HRC retains discretion to consider other factors (including our performance relative to our peers, other key performance indicators and market conditions) in assessing the strength of the corporate performance metrics and also retains discretion to determine the overall corporate performance payout.
The HRC Committee agreed to the use of DCF per share as the corporate performance metric because it believes DCF per share is an appropriate measure of financial
performance for the enterprise. Focusing management on this metric will enhance transparency of Enbridge’s cash flow growth, increase comparability of results relative to peers and help ensure full value recognition for Enbridge’s superior assets and commercial and growth arrangements, which provides a low risk value proposition for shareholders.
For 2020, DCF per share targets were set using the external financial guidance range to determine threshold and target payments. For any payout to occur, Enbridge must achieve threshold performance. For a maximum payout to occur, Enbridge must achieve the top of the guidance range, which ensures there is appropriate stretch in the plan. Despite the unprecedented impact of
COVID-19
and reduced energy demand, the targets were not revised
in-year.
For purposes of Enbridge’s 2020 STIP awards, 2020 DCF per share was determined to be $4.69 and resulted in a performance multiplier of 1.27x, representing 100% of the corporate performance metric. No discretion was applied beyond standard normalizations.
  2020 corporate STIP metric
            DCF per share
1
          Performance multiplier
2
  Threshold (guidance minimum)
$4.50
0.5x
  Target (guidance midpoint)
$4.65
1.0x
  Maximum (guidance maximum)
$4.80
2.0x
  Actual
$4.69
1.27x
1
DCF per share is a
non-GAAP
measure; this measure is defined and reconciled in Item 11 –
“Non-GAAP
reconciliation”.
2
DCF per share between thresholds in this table result in a performance multiplier calculated on a linear basis.
Business unit performance
The HRC Committee approved the application of the following scorecards for each of the NEOs. While the specific metrics used vary by business unit, each scorecard includes objectives relating to operational performance and reliability, financial performance and project execution as outlined below:
  Executive
Business unit metrics
Description
Al Monaco
Composite measure
1
•  Non-financial
operating measures for the combined enterprise (including enterprise safety and environment)
Colin K. Gruending
Central Functions
•  Weighted average of overall business unit results
•  Financial (corporate cost containment)
John K. Whelen
Central Functions (70%)
•  Weighted average of overall business unit results
•  Financial (corporate cost containment)
Energy Marketing (20%)
•  Financial, operating and commercial measures for the Energy Marketing business unit
Power Operations (10%)
•  Financial, operating and commercial measures for the Power Operations business unit
William T. Yardley
Gas Transmission and Midstream
•  Financial, operating and commercial measures for the Gas Transmission and Midstream business unit
Vern D. Yu
Liquids Pipelines
•  Financial, operating and commercial measures for the Liquids Pipelines business unit
Robert R. Rooney
Central Functions
•  Weighted average of overall business unit results
•  Financial (corporate cost containment)
1
The business unit metric for Mr. Monaco is a composite measure, representing enterprise-wide performance as, in his capacity as President & CEO, he oversees the overall organization.
26

Individual performance
In the first quarter of 2020, after discussion with the Board, the HRC Committee approved individual performance objectives for Mr. Monaco, taking into consideration the company’s financial and strategic priorities. For our other NEOs, Mr. Monaco established their individual objectives for 2020 at the start of the year, based on strategic and operational priorities related to each executive’s portfolio and other factors.
Short-term incentive award outcomes
Each NEO’s calculated STIP award, as well as the actual award, is as follows:
Executive
  
Corporate
multiplier
   
x
   
Weight
  
+
   
Business
Unit
multiplier
   
x
   
Weight
  
+
   
Individual
multiplier
   
x
   
Weight
  
=
   
Overall
multiplier
 
Al Monaco
   1.27    x    60  +    1.34    x    20  +    2.00    x    20  =    1.43 
Colin K. Gruending
   1.27    x    60  +    1.50    x    20  +    1.90    x    20  =    1.44 
John K. Whelen
   1.27    x    60  +    1.56    x    20  +    1.70    x    20  =    1.41 
William T. Yardley
   1.27    x    40  +    1.15    x    40  +    1.90    x    20  =    1.35 
Vern D. Yu
   1.27    x    40  +    0.95    x    40  +    1.90    x    20  =    1.27 
Robert R. Rooney
   1.27    x    60  +    1.50    x    20  +    1.80    x    20  =    1.42 
Short-term incentive award calculations
Enbridge delivered strong results in 2020 driven by solid operating performance across the entire asset base despite the unprecedented impact of
COVID-19
and reduced energy demand, demonstrating the resiliency of cashflows associated with Enbridge’s
low-risk
business model. Though the business environment changed drastically because of these crises, management was held to account against the original 2020 STIP targets set at the beginning of the year and well in advance of
COVID-19.
Performance outcomes are based on actual results relative to the agreed targets and were achieved through early, swift and sustained management actions throughout 2020. Furthermore, no discretion was requested nor applied to the calculated awards.
Executive
  
Base salary
1 2

($)
   
x
   
STIP target
(%)
  
x
   
Overall
multiplier
   
=
   
Calculated
award ($)
1
   
Actual award
($)
1
 
Al Monaco
   1,546,139    x    145  x    1.43    =    3,205,919    3,205,919 
Colin K. Gruending
   587,074    x    90  x    1.44    =    761,904    761,904 
John K. Whelen
   542,492    x    90  x    1.41    =    690,766    690,766 
William T. Yardley
   700,018    x    90  x    1.35    =    849,262    849,262 
Vern D. Yu
   616,801    x    90  x    1.27    =    703,893    703,893 
Robert R. Rooney
   557,394    x    80  x    1.42    =    634,091    634,091 
1
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
2
Base salary used in the calculation is reflective of base salary earned in 2020.
Medium- and long-term incentives
Medium- and long-term incentive awards were granted in 2020 under the Enbridge Inc. 2019 Long Term Incentive Plan (2019 LTIP).
In 2020, we introduced share-settled restricted stock units (“RSUs”) into the overall pay mix, enhancing retentive value and maintaining alignment with shareholders. This change aligns with our strategy and the competitive market while maintaining the majority of our pay mix in
performance-based
vehicles to align with our
pay-for-performance philosophy.
Enbridge’s medium- and long-term incentive for executives includes three primary vehicles: performance stock units (“PSUs”), RSUs and incentive stock options (“ISOs”).
Enbridge’s medium- and long-term incentives are forward-looking compensation vehicles, and as such, grants are considered part of the compensation for the year of grant and onward instead of in recognition of prior performance or previously granted awards.
The various awards that apply to executives have different terms, vesting conditions and performance criteria, mitigating the risk that executives produce only short-term results. This approach also benefits shareholders and helps maximize the ongoing retentive value of the medium- and long-term incentives granted to executives.
27

Medium- and long-term incentive grants are determined as follows:
The table below outlines the medium- and long-term incentive plans used in 2020.
PSU
RSU
ISO
Term
Three yearsThree years10 years
Description
Phantom share/units with performance conditions that affect the payoutPhantom share/units
Options to acquire Enbridge shares
For U.S. participants, awards are granted in
non-qualified
options that do not meet the requirements of section 422 of the U.S. Internal Revenue Code
Frequency
Granted annuallyGranted annuallyGranted annually
Performance conditions
50% DCF per share growth relative to a target set at the beginning of the term
n/an/a
50% total shareholder return (“TSR”) performance relative to peers
Vesting
Units cliff vest at the end of the term including dividend equivalents as additional unitsUnits cliff vest at the end of the term including dividend equivalents as additional unitsOptions vest 25% per year over four years, starting on the first anniversary of the grant date
Payout
Paid out in cash based on market value of an Enbridge share at the end of the term, subject to adjustment from
0-200%
based on achievement of the performance conditions above
Settled in shares at the end of the termParticipant acquires Enbridge shares at the exercise price defined as fair market value at the time of grant
Medium- and long-term incentive targets (as a % of base salary)
The table below shows the target medium- and long-term incentive awards for each NEO in 2020, as well as the amount each plan contributes to that total, in each case as a percentage of base salary. These targets represent a 60%/20%/20% PSU/RSU/ISO vehicle mix.
  Executive
 
Total 2020 target
medium- and long-
term incentives
  
Annual grant
 
 
PSUs
 
RSUs
  
ISOs
 
  Al Monaco
  650 390%  130  130
  Colin K. Gruending
  400 240%  80  80
  John K. Whelen
  400 240%  80  80
  William T. Yardley
  400 240%  80  80
  Vern D. Yu
  400 240%  80  80
  Robert R. Rooney
  350 210%  70  70
28

Performance stock units
PSUs are granted annually, in the first quarter of the year, and vest after three years based on the achievement of
pre-established
and specific performance measures; the executives’ potential payout at the end of the performance period can range from 0% to 200% of the target award depending on the level of achievement of the performance measures.
For grants in 2020, the following two performance measures were used, each weighted at 50%:
DCF per share growth.
This measure represents a commitment to Enbridge shareholders to achieve distributable cash flow growth that demonstrates Enbridge’s ability to deliver on its growth plan and continued dividend increases. Measurement against Enbridge’s long-range plan, as well as against industry growth rates, differentiates this metric compared to its use in the STIP, which is based on the
1-year
external guidance range. The different measurement standards are designed to avoid excessive overlap between Enbridge’s compensation programs. Furthermore, DCF per share growth is only one of two equally weighted metrics used for PSUs.
Relative TSR.
This measure is used to compare Enbridge against its performance comparator group. For this measure, Enbridge compares itself against the following group of companies, chosen because they are all capital market competitors, operating in a comparable industry sector.
Performance comparator group: relative TSR
Canadian Utilities Limited
NextEra Energy Inc.
CenterPoint Energy, Inc.
NiSource Inc.
Dominion Resources
ONEOK, Inc.
DTE Energy Company
Pembina Pipeline Corporation
Duke Energy Corporation
PG&E Corporation
Energy Transfer LP
Plains All American Pipeline, L.P.
Enterprise Products Partners, L.P.
Sempra Energy
Fortis Inc.
The Southern Company
Inter Pipeline Ltd.
TC Energy Corporation
Kinder Morgan, Inc.
The Williams Companies, Inc.
Magellan Midstream Partners, L.P.
Payout is determined at the end of the three-year term using an actual performance multiplier that ranges from 0% to 200% depending on whether the performance conditions are met. The final Enbridge share price for payout is the volume weighted average trading price of Enbridge shares on the TSX or NYSE for the 20 trading days immediately preceding the maturity date, on which performance is certified. Payout is made in cash.
2020 performance stock unit grant
The mechanics of the 2020 PSU grant is illustrated below.
29

The following PSU grants were made to the NEOs in 2020:
  Executive
  
Number of PSUs granted (#)
   
Grant value (as % of base salary)
1
 
  Al Monaco
   
124,500
    
390%
 
  Colin K. Gruending
   
24,680
    
240%
 
  John K. Whelen
   
30,140
    
240%
 
  William T. Yardley
   
35,260
    
240%
 
  Vern D. Yu
   
26,760
    
240%
 
  Robert R. Rooney
   
23,410
    
210%
 
1
PSU grant sizes were based on the
20-day
volume weighted average share price immediately preceding January 1, 2020.
Restricted stock units
RSUs are granted annually, in the first quarter of the year, and vest after three years. Payout is determined at the end of the three-year term. The final Enbridge share price at the end of the term is the volume weighted average trading price of Enbridge shares on the TSX or NYSE for the last 20 trading days before the end of the term. These awards, including dividend equivalents accrued as additional RSUs, are settled in Enbridge shares.
2020 restricted stock unit grant
The following RSU grants were made to the NEOs in 2020:
  Executive
  
Number of RSUs granted (#)
   
Grant value (as % of base salary)
1
 
  Al Monaco
   
41,500
    
130%
 
  Colin K. Gruending
   
8,230
    
80%
 
  John K. Whelen
   
10,050
    
80%
 
  William T. Yardley
   
11,750
    
80%
 
  Vern D. Yu
   
8,920
    
80%
 
  Robert R. Rooney
   
7,800
    
70%
 
1
RSU grant sizes were based on the
20-day
volume weighted average share price immediately preceding January 1, 2020.
Incentive stock options
ISOs provide executives an opportunity to buy Enbridge shares at some point in the future at the exercise price defined at the time of grant. Members of Enbridge’s senior management, including all of the NEOs, are eligible to receive ISOs.
ISOs are typically granted in February or March every year to both Canadian and U.S. members of senior management. ISOs vest in equal instalments over a four-year period. The maximum term of an ISO is 10 years, but the term can be reduced if the executive leaves Enbridge as described in the “Termination provisions of equity compensation plans” section. The exercise price of an ISO is the closing price of an Enbridge share on the listed exchange the last trading day before the grant date. The grant date will be no earlier than the third trading day after a trading blackout period ends. ISOs are never backdated or
re-priced.
ISOs may be granted to executives when they join Enbridge, normally effective on the executive’s date of hire. If the hire date falls within a blackout period, the grant is delayed until after the end of the blackout period.
30

2020 incentive stock option grant
The following ISO grants were made to the NEOs in 2020:
  Executive
  
Number of ISOs granted (#)
   
Grant value (as % of base salary)
1
 
  Al Monaco
   614,200    130
  Colin K. Gruending
   121,740    80
  John K. Whelen
   148,680    80
  William T. Yardley
   129,020    80
  Vern D. Yu
   132,010    80
  Robert R. Rooney
   115,510    70
1
Differences in value as reported in the 2020 summary compensation table are not reflective of discretionary adjustments but rather are due to differences in valuations using the Black-Scholes model at the time of approval and grant date.
Awards vesting in 2020
2018 performance stock unit payout
The PSUs granted in February 2018 matured on December 31, 2020 and both performance targets were exceeded. The DCF per share compound growth was 9.15%, while the relative TSR performance placed at the 77th percentile. The overall performance multiplier of 1.82x was calculated based on the following metrics:
        Multiplier
1
        DCF per share compound growth        
TSR
  Threshold
0.0x
3.4%
at or below 25th percentile
  Target
1.0x
6.0%
at median
  Maximum
2.0x
11.0%
at or above 75th percentile
  Actual
1.82x
9.15% (1.63x multiplier)
77th percentile (2.00x multiplier)
1
Performance between the thresholds in this table results in a performance multiplier calculated on a linear basis.
Adjusted DCF per share is based on operating cash flows and is a
non-GAAP
measure, which is defined and reconciled in Item 11 –
“Non-GAAP
reconciliation”.
For incentive compensation purposes, adjusted DCF per share also includes certain adjustments for events or circumstances not contemplated at the time the performance metrics were originally established – see Item 11 – “Non-GAAP reconciliation”.
The performance peer group for the 2018 PSU payout was as follows:
  Performance comparator group: relative TSR
  Canadian Utilities Limited
NiSource Inc.
  Dominion Resources
ONEOK, Inc.
  DTE Energy Company
Pembina Pipeline Corporation
  Energy Transfer LP
PG&E Corporation
  Enterprise Products Partners, L.P.
Plains All American Pipeline, L.P.
  Fortis Inc.
Sempra Energy
  Inter Pipeline Ltd.
TC Energy Corporation
  Kinder Morgan, Inc.
The Williams Companies, Inc.
  Magellan Midstream Partners, L.P.
31

This resulted in the following payouts for the NEOs in early 2021:
  Executive
  
PSUs
granted
(#)
   
+
   
Notionally
reinvested
dividends
(#)
   
Total
PSUs
(#)
   
x
   
Performance
multiplier
   
x
   
Final
share
price
1 2

($)
   
=
   
Payout
($)
 
  Al Monaco
   103,590    +    22,849    126,439    x    1.82x    x    42.26    =    9,724,864 
  Colin K. Gruending
   6,440    +    1,421    7,861    x    1.82x    x    42.26    =    604,577 
  John K. Whelen
   27,125    +    5,983    33,108    x    1.82x    x    42.26    =    2,546,456 
  William T. Yardley
   32,070    +    7,092    39,162    x    1.82x    x    41.88    =    2,984,853 
  Vern D. Yu
   16,440    +    3,626    20,066    x    1.82x    x    42.26    =    1,543,361 
  Robert R. Rooney
   20,090    +    4,431    24,521    x    1.82x    x    42.26    =    1,886,017 
1
The volume weighted average share price of an Enbridge share on the TSX or NYSE for the 20 trading days immediately preceding December 31, 2020.
2
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
2017 Spectra Energy phantom stock unit payout
The 2017 Spectra Energy phantom stock units granted to Mr. Yardley on February 14, 2017 vested on February 14, 2020.
  Executive
  
Total
phantom
stock units
(#)
   
x
   
Final
share
price
1 2

($)
   
=
   
Payout
($)
2 3
 
  William T. Yardley
   17,908    x    53.76    =    962,820 
1
The closing price of an Enbridge share on the NYSE on February 14, 2020.
2
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
3
In addition to the amount above, a dividend payout in cash of US$109,938 was made.
2018 restricted stock unit payout
Mr. Gruending received a 2018 RSU grant which vested on December 1, 2020.
  Executive
  
RSUs
granted
(#)
  
+
  
Notionally
reinvested
dividends
(#)
  
Total
RSUs
(#)
  
x
  
Final
share
price
1

($)
  
=
  
Payout
($)
  Colin K. Gruending
  4,960  +  998  5,958  x  38.25  =  227,877
1
The volume weighted average share price of an Enbridge share on the TSX for the 20 trading days immediately preceding December 1, 2020.
2019 restricted stock unit payout
On May 8, 2019, Mr. Yardley was awarded a retention award given his critical role in delivering Gas Transmission and Midstream strategic priorities. This award consisted of 40,421 RSUs, 20% of which vested on May 8, 2020, the first anniversary of the grant. Another 20% of the award will vest on the second anniversary, and the remaining 60% on the third anniversary of the grant date. The table below outlines the tranche that vested in 2020:
  Executive
  
RSUs
granted
(#)
   
+
   
Notionally
reinvested
dividends
(#)
   
Total
RSUs
(#)
   
x
   
Final
share
price
1 2

($)
   
=
   
Payout
2

($)
 
  William T. Yardley
   8,084    +    522    8,606    x    37.61    =    323,675 
1
The volume weighted average share price of an Enbridge share on the NYSE for the 20 trading days immediately preceding May 8, 2020.
2
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
32

2021 changes
Enbridge has always integrated ESG into its strategy and decisions and takes pride in its industry leadership. To reinforce this, management took two important steps; the introduction of Inclusion as a core company value and, in November 2020, the announcement of ESG goals, including for GHG emissions reduction and increased diversity and inclusion within Enbridge’s workforce and on its Board of Directors. Of note, and further reinforcing accountability to stakeholders, beginning in 2021, progress towards goals will be reflected in incentive compensation for all employees, including the CEO and executive management.
2020 was an unprecedented year for Enbridge due to the impact of
COVID-19,
reduced demand for energy and reduced commodity prices. In response to these factors, management implemented voluntary base salary reductions for NEOs, as outlined in the 2020 compensation decisions. This action supported our short-term cost reduction initiative in response to the
potential financial implications of the business environment at that time. We have been closely monitoring the impact that our base salary reductions have had on our competitiveness. In light of the success of our cost reduction initiative, business performance in 2020 and to align with our compensation philosophy of providing market competitive pay levels, reinstatement of
pre-rollback
base salaries will take place in 2021.
On February 18, 2021, Mr. Yu was awarded a $2 million retention award given his critical role in delivering Liquids Pipelines strategic priorities and the execution of Enbridge’s overall strategy. The award was delivered in the form of RSUs to align with the shareholder experience over the term. 20% of the award will vest on each of the first and second anniversaries of the grant date, with the remainder of such award vesting on the third anniversary of grant, in each case, subject to Mr. Yu’s continued employment with Enbridge.
Total direct compensation for Named Executive Officers
Profiles have been prepared for each of the NEOs that provide:
A summary of individual accomplishments in 2020; and
2020 pay mix (2020 base salary, STIP with respect to 2020 and medium- and long-term incentives granted in 2020).
The values provided in the NEOs’ profiles are taken from the 2020 summary compensation table.
33

Al Monaco
President & CEO
Mr. Monaco is responsible for setting and executing Enbridge’s strategic priorities and serves on the company’s Board of Directors.
In 2020, Mr. Monaco provided strategic and executive leadership in the following areas:
Health, safety and wellbeing of our workforce in a global pandemic
Operational reliability and undisrupted delivery service to customers across all of our systems in a pandemic-challenged environment
Early and decisive action in mitigating the financial impact of
COVID-19
and severe disruption in North American energy demand
Achievement of DCF per share budget despite unprecedented industry downturn and loss of liquids pipeline throughput
Maintaining strong balance sheet and increasing financial liquidity that protected the business in a volatile and unpredictable operating and capital markets environment
Achievement of substantial overhead savings, including through voluntary workforce reduction program while retaining critical staff and improving employee engagement
Dividend increase of 10%—25th consecutive year
Obtaining all regulatory approvals and permits and commenced Line 3 Replacement Program construction in Minnesota
Completion and into service of $1.6 billion of capital projects
Securing an additional $5 billion of new growth projects
Sale of $0.4 billion of
non-core
assets
Achievement of
Debt-to-EBITDA
at 4.6x, which is at the low end of the target leverage range
Establishment of industry leading emissions reductions targets tied to executive compensation
Establishment of diversity and inclusion targets tied to executive compensation
Establishment of extended
3-year
growth outlook and revised capital allocation framework
Advancement of lower carbon footprint strategy including growth in offshore renewables business – one new project sanctioned; two projects began construction
Significant shareholder engagement and
top-rated
investor relations program
Senior management rotations supporting development/succession planning
President & CEO compensation
Our President & CEO is primarily responsible for executing our long-term business strategy as well as shorter-term strategies that support our long-term objectives. The HRC Committee recognizes that Mr. Monaco is managing a changing and increasingly complex business and that it is important to reward these efforts. In 2020, these efforts included decisive action to mitigate the impact of
COVID-19
on our financial and operational performance as well as on the health and safety of our employees, customers and communities. The HRC Committee believes Mr. Monaco’s compensation should be consistent with this level of responsibility and thus evaluates his pay annually and, if necessary, adjusts it to ensure it is aligned with the market and our strategic goals. Recent adjustments to certain elements of Mr. Monaco’s pay have resulted in an increase in his target total direct compensation. These adjustments demonstrate the HRC Committee’s efforts to bring his pay closer to the market median, using a
phased-in
approach over a period of years, and to recognize his role in the company’s success. Consistent with our philosophy, a significant portion of the overall increase was delivered through LTIP, which are aligned to the achievement of our strategic priorities and with shareholder interests.
     
34

Colin K. Gruending
Executive Vice President & Chief Financial Officer
Mr. Gruending is responsible for all corporate financial affairs of the company, including financial planning and reporting, tax, treasury and financial risk management.
In 2020, Mr. Gruending provided strategic and executive oversight in the following areas:
Stewardship of the company’s financial performance to achieve budgeted results, notwithstanding challenges posed by
COVID-19
and related lower transportation demand, including the swift development and implementation of a cost reduction and amended financing plan to retain maximum enterprise strength, in the case of a prolonged pandemic
Raising $8.5 billion of long-term capital on attractive terms in support of the company’s growth program
Stewardship of the capital allocation framework and sustained and strengthened Enbridge’s financial position
(Debt-to-EBITDA
ratio of 4.6x, which is at the low end of the stated target range)
Advancement of the execution of Enbridge’s Enterprise Resource Planning implementation, an initiative to automate and harmonize key financial and work management systems
Development of the 2021 budget, financing plan, and
3-year
outlook
The company’s accounting, treasury, risk management, taxation, audit, and investor relations functions, including the development of top talent and strengthening engagement levels
   
John K. Whelen
Former Executive Vice President
Mr. Whelen was responsible for all corporate development affairs of the company, strategy and planning, Energy Services and the Power business.
In 2020, Mr. Whelen provided strategic and executive oversight in the following areas:
Development and implementation of a dynamic strategic planning framework to assess and respond to challenges and opportunities arising from the impact of
COVID-19
and energy market disruptions
Delivery of an updated strategic plan in response to evolving energy fundamentals and changes in Enbridge’s business environment
Development of a framework and methodologies to support the implementation of enterprise-wide GHG emissions reduction goals and related measures that were announced in November of 2020
Advancement of a number of renewable power projects under construction or in earlier stages of development, including development and implementation of a strategy to develop renewable electric generation facilities to power Enbridge’s core operations
Development of staff and senior management for broader roles, ensuring a smooth succession and transition to new leadership of Corporate Development functions upon his retirement in November of 2020
   
35

William T. Yardley
Executive Vice President & President, Gas Transmission & Midstream
Mr. Yardley is responsible for Enbridge’s natural gas transmission and midstream business across North America.
In 2020, Mr. Yardley provided strategic and executive oversight in the following areas:
Completion of a transformational year in the system-wide asset integrity and modernization program
Implementation of rate initiatives on Algonquin and Texas Eastern, and filed rate proceedings on East Tennessee Natural Gas, Maritimes & Northeast Pipeline and Alliance Pipeline
Completion of the first-ever solar self-power project in Lambertville, NJ, a major step in a system-wide emissions reduction effort
Major contract renewal effort, achieving a revenue renewal rate of over 99% with customers on our major pipelines
Championing safe and responsible operations, resulting in a 50% decrease in business unit recordable injury frequency among employees and contractors and a 40% decrease in environmental incident frequency from 2019
Keeping US$3 billion of projects on track for
in-service
dates
Identifying $2 billion per year of future development opportunities
Securing pipeline agreements for liquefied natural gas projects for up to US$4 billion in investment opportunity, advancing gulf coast strategy
Demonstration of operational resiliency with minimal impacts to customers associated with 12 named tropical storms and hurricanes impacting Gas Transmission and Midstream assets in 2020
Ensuring safe continuity of operations at all times during the
COVID-19
pandemic

Vern D. Yu
Executive Vice President & President, Liquids Pipelines
Mr. Yu is responsible for Enbridge’s crude oil and liquids pipeline business across North America.
In 2020, Mr. Yu provided strategic and executive oversight in the following areas:
Implementation of significant new health and safety protocols related to
COVID-19
to ensure that the Liquids Pipelines system operated uninterrupted in 2020
Achievement of above target reliability
Achievement of 2020 financial performance within target range for Liquids Pipelines, overcoming an unprecedented reduction in refinery demand and an associated reduction in Mainline volumes due to
COVID-19
Implementation of significant system and cost efficiencies to offset reduced Mainline throughput
Achievement of record high volumes to the U.S. Gulf Coast through the Market Access pipelines
Completion of the North Dakota section of the Line 3 Replacement Program on budget and on schedule
Obtaining all necessary State and Federal permits to begin construction of the Minnesota section of the Line 3 Replacement Program
Progressing the regulatory process for Mainline contracting with the Canada Energy Regulator, answering more than 3,300 interrogatory requests
Completion of Line 5 tunnel permit applications
Implementation of a diversity plan for Liquids Pipelines and improved diversity within the leadership team

36

Robert R. Rooney
Executive Vice President & Chief Legal Officer
Mr. Rooney is responsible for the legal, ethics and compliance, security and aviation functions across Enbridge.
In 2020, Mr. Rooney provided executive oversight for a number of substantial legal, business and regulatory matters, including:
Acquiring all permits, approvals and judicial decisions necessary to commence construction of the Line 3 Replacement Program in Minnesota
Legal and regulatory aspects of the Ontario Energy Board approvals to advance Enbridge’s renewable natural gas and hydrogen projects
Legal and regulatory aspects for the
T-North
and
T-South
expansion projects in British Columbia
Legal and regulatory strategy for Line 5 in Michigan to maintain operations and advance the Great Lakes Tunnel project
Legal aspects of the European offshore wind business that achieved final investment decision at Fécamp, acquisition of an interest in Mistral and sell-downs to Canada Pension Plan Investment Board
Development of a new strategic plan for Security to support the company
Primary legal support for all corporate finance activities
Effective corporate governance and supported leading ESG practices
Legal and regulatory strategy for the Mainline contracting application to the Canada Energy Regulator
Management of the Aviation function to provide safe and efficient pipeline patrols and services
Continued advancement of our workforce diversity and inclusion initiatives
   
37

Other benefits elements
Retirement benefits
The NEOs participate in the Senior Management Pension Plan (“SMPP”), a
non-contributory
defined benefit plan that provides market competitive retirement income to all Canadian and U.S. members of senior management. Before becoming participants in the SMPP, certain NEOs participated in a
non-contributory
defined benefit or defined contribution pension plan.
Defined benefit plan
The following graphic shows how the SMPP retirement benefit payable at normal retirement age is calculated:

Key terms of the SMPP:
Eligibility: members of senior management join the SMPP on the later of their date of hire or promotion to a senior management position;
Vesting: plan participants are fully vested immediately;
Retirement age: normal retirement date is age 65. Participants can retire with an unreduced pension at age 60, or as early as age 55 if they have 30 years of service. If they have less than 30 years of service, they can still retire as early as age 55, but their retirement benefit is reduced by 3% per year before age 60;
Adjustment for inflation: retirement benefits are indexed at 50% of the annual increase in the consumer index price; and
Survivor benefits: the pension is payable for the life of the member. If the member is single at retirement, 15 years of pension payments are guaranteed. If the member is married at retirement and dies before their spouse, 60% of the pension will continue to be paid to the spouse for his/her lifetime.
The SMPP consists of benefits paid from the following
tax-qualified
and supplemental pension plans, collectively referred to as the SMPP:
Retirement Plan for Employees of Enbridge Inc. and Affiliates;
Enbridge Employee Services, Inc. Employees’ Pension Plan;
Enbridge Supplemental Pension Plan; and
Enbridge Employee Services Inc. Supplemental Pension Plan for United States Employees
Prior to the merger of Enbridge Inc. and Spectra Energy Corp (the Merger Transaction), Mr. Yardley participated in a qualified and a
non-qualified
cash balance arrangement, to which there are no further contributions or service accruals.
38

Summary of defined benefits
The following table outlines estimated annual retirement benefits, accrued pension obligations and compensatory and
non-compensatory
changes for the NEOs under the defined benefit pension plans. All information is based on the assumptions and methods used for the purposes of reporting the company’s financial statements and which are described in the company’s financial statements.
  Executive
8
 
Credited
service
(years)
  
Annual benefits payable
  
Accrued
obligation at
Jan 1, 2020
($)
  
Compensatory
change
1
($)
  
Non-
compensatory
change
2
($)
  
Accrued
obligation at
Dec 31, 2020
($)
 
 
At year end
($)
  
At age 65
($)
 
 
A
  
B
  
C
  
A+B+C
 
  Al Monaco
3
  22.08   1,463,000   1,625,000   26,182,000   1,462,000   2,333,000   29,977,000 
  Colin K. Gruending
4
  17.25   232,000   530,000   4,681,000   1,017,000   675,000   6,373,000 
  John K. Whelen
5
  23.03   447,000   447,000   8,039,000   525,000   1,438,000   10,002,000 
  William T. Yardley
6 7
  20.13   201,000   363,000   2,778,000   396,000   289,000   3,463,000 
  Vern D. Yu
  19.75   343,000   525,000   6,368,000   1,177,000   877,000   8,422,000 
  Robert R. Rooney
  3.92   67,000   86,000   895,000   349,000   136,000   1,380,000 
1
The components of compensatory change are current service cost and the difference between actual and estimated pensionable earnings.
2
The
non-compensatory
change includes interest on the accrued obligation at the start of the year, changes in actuarial assumptions and other experience gains and losses not related to compensation.
3
Mr. Monaco’s retirement benefit is calculated using a 2.5% accrual rate for each year of credited service between 2008 and 2013. The higher accrual rate is equivalent to approximately 1.50 years of credited service. Upon Mr. Monaco’s appointment to President & CEO, a cap to the annual pension payable of $1,750,000 was implemented.
4
Mr. Gruending’s SMPP retirement benefits earned after December 31, 2017 are not indexed for inflation.
5
Mr. Whelen’s annual benefits payable and accrued obligation at year end reflects his retirement in 2020.
6
The impact of changes to exchange rates on Mr. Yardley’s accrued obligation is reflected in the
non-compensatory
change. The accrued obligation for Mr. Yardley’s cash balance retirement benefits prior to joining the SMPP are US$1,019,509 at the start of the year and US$1,060,289 at year end.
7
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
8
In 2020, all NEOs were granted a temporary hold-harmless against a reduction to their SMPP pension resulting from the significant reductions in base salary should they retire within 5 years of the reduction. These base salary reductions were related to the impacts of
COVID-19,
reduced energy demand and reduced commodity prices, and were not intended to have a permanent impact on the SMPP lifetime pensions. As indicated under “2021 changes” on page 33, NEO base salaries are to be reinstated in 2021.
Defined contribution plan
The defined contribution pension plan is a
non-contributory
pension plan. The level of contribution varies, depending on age and years of service. None of the NEOs are currently participating in the defined contribution pension plan.
Mr. Monaco, Mr. Gruending, Mr. Whelen and Mr. Yu participated in the defined contribution plan for three years, four years, four years and five years, respectively, prior to joining the SMPP. The values shown below reflect market value of assets of the defined contribution plan.
  Executive
  
    Accumulated value at Jan 1,
2020
($)
   
Compensatory change
1
($)
   
    Accumulated value at Dec 31,
2020
($)
 
  Al Monaco
   72,413    -    77,811 
  Colin K. Gruending
   79,400    -    82,499 
  John K. Whelen
   79,579    -    83,086 
  Vern D. Yu
   79,916    -    84,966 
1
The compensatory change is equal to contributions made by the company during 2020.
39

Other benefits
Enbridge’s savings plan and benefits plans are key elements of the total compensation package for our employees, including NEOs.
Savings Plan
Enbridge provides a savings plan for Canadian employees and a 401(k) savings plan for U.S. employees. All NEOs participate in the savings plan on the same terms as eligible employees. The savings plans assist and encourage employees to save by matching 100% of employee contributions up to plan limits (maximum 2.5% and 6% of base salary for Canadian employees and U.S. employees, respectively) and subject to applicable tax limits. In Canada, matching contributions are provided as flex credits which may be used to purchase additional benefits or taken as
after-tax
cash; in the U.S., matching contributions are invested in the savings plan.
Life and health benefits
Medical, dental, life insurance and disability insurance benefits are available to meet the specific needs of individuals and their families. The NEOs participate in the same plan as all other employees. The plans are structured to provide minimum basic coverage with the option of enhanced coverage at a level that is competitive and affordable.
The HRC Committee reviews the retirement and other benefits regularly. These benefits are a key element of a total compensation package and are designed to be competitive and reasonably meet the needs of executives in their current roles.
Compensation governance
Enbridge’s compensation governance structure consists of the Board and the HRC Committee, with Mercer (Canada) Limited (“Mercer”), and others from time to time, providing independent advisory support to the HRC Committee. The HRC Committee reviews the governance structure annually against best practices and regulatory guidance.
Board and HRC Committee
The Board is responsible for the oversight of the compensation principles and programs at Enbridge. The HRC Committee approves major compensation programs and payouts, including reviewing and recommending the compensation for the President & CEO to the Board. The HRC Committee also approves the compensation for the other NEOs.
The HRC Committee assists the Board in carrying out its responsibilities with respect to compensation matters by providing oversight and direction on human resources strategy, policies and programs for the NEOs, senior
management and the broader employee base. This includes compensation, equity incentive plans, pension and benefits as well as talent management, succession planning, workforce recruitment, retention, diversity and inclusion, and employee health and safety in response to the
COVID-19
pandemic. The HRC Committee provides oversight regarding the management of broader people-related risk and, in addition, specifically reviews the compensation programs from a risk perspective.
All members of the HRC Committee are independent under the independence standard discussed in this Amendment No. 1 on Form 10-K/A. The members of the HRC Committee are V. Maureen Kempston Darkes (chair), Pamela L. Carter, Marcel R. Coutu, Susan M. Cunningham and Gregory J. Goff.
The members of the HRC Committee have experience as members of the compensation committees of other public companies. In addition, the members of the HRC Committee have experience in top leadership roles, strong knowledge of the energy industry, experience as directors of other public companies, and a mix of other relevant skills and experience. This background provides the HRC Committee members with the collective experience, knowledge and skills to effectively carry out their responsibilities. For information on each HRC Committee member’s experience and current service on other public company boards and committees, see the director profiles, beginning on page 4. For information on each HRC Committee member’s skills and experience, see the skills and experience matrix on page 15. For information on each HRC Committee member’s participation on other Board committees, see page 14.
Independent advice
The HRC Committee is directly responsible for the appointment, compensation and oversight of the work of any compensation consultants, outside legal counsel or other advisors it retains (each, an “Advisor”). The HRC Committee may select or receive advice from an Advisor only after taking into consideration all factors relevant to the Advisor’s independence from management including:
the provision of other services to Enbridge by the Advisor;
the amount of fees received from Enbridge by the Advisor as a percentage of the Advisor’s total revenue;
the policies and procedures of the Advisor that are designed to prevent conflicts of interest;
any shares owned by the Advisor; and
any business or personal relationship of the Advisor with a member of the HRC Committee or with an executive officer at Enbridge.
Although the HRC Committee is required to consider these factors, it is free to select or receive advice from an Advisor that is not independent. The HRC Committee has determined that Mercer, as an Advisor, is independent.
40

Since 2002, Mercer, an independent Advisor, has provided guidance to the HRC Committee on compensation matters to ensure Enbridge’s programs are appropriate, market competitive and continue to meet intended goals. Advisory services include reviewing:
the competitiveness and appropriateness of executive compensation programs;
annual total direct compensation for the President & CEO and the executive leadership team;
executive compensation governance; and
the HRC Committee’s mandate and related Board committee processes.
While the HRC Committee considers the information and recommendations Mercer provides, it has full responsibility for its own decisions, which may reflect other factors and considerations.
The HRC Committee chair reviews and approves the terms of engagement with Mercer every year. The terms specify the work to be done in the year, Mercer’s responsibilities and its fees. Management can also retain Mercer on compensation matters from time to time or for prescribed compensation services. The HRC Committee chair must, however, approve all services that are not standard in nature, considering whether or not the work would compromise Mercer’s independence.
Management and the HRC Committee engaged Mercer in 2020 to provide analysis and advice on various compensation matters. The following table provides a breakdown of services provided by and fees paid to Mercer and its affiliates (a significant portion of which relate to risk brokerage service fees paid to Marsh Inc., a Mercer affiliate) by Enbridge and its affiliates in 2020 and 2019:
  Nature of work
  
Approximate fees in 2020 ($)
  
Approximate fees in 2019 ($)
  Executive compensation related fees
1
   
 
296,735
 
   
 
296,632
  All other fees
2
   
 
5,658,518
 
   
 
6,148,371
  Total
   
 
5,955,253
 
   
 
6,445,003
 
1
Includes all fees related to executive compensation associated with the President & CEO and the executive leadership team.
2
Includes fees paid for other matters that apply to Enbridge as a whole, such as pension actuarial valuations, renewal and pricing of benefit plans, evaluation of geographic market differences and regulatory proceedings support. Also includes significant risk brokerage service fees paid to Marsh for services provided to our operating affiliates.
Compensation services received by Enbridge from Advisors are not sole sourced from one provider; each situation and need is assessed independently, and other providers are used depending on the nature of the service required, and the qualifications of the provider. In 2020, Enbridge did not engage the services of other compensation consultants.
Compensation risk management
The HRC Committee oversees Enbridge’s compensation programs from the perspective of whether the programs encourage individuals to take inappropriate or excessive risks that are reasonably likely to have a material adverse impact on Enbridge.
Compensation risk mitigation practices
Enbridge uses the following compensation practices to mitigate risk:
a
pay-for-performance
philosophy that is embedded in the compensation design;
a mix of pay programs benchmarked against a relevant peer group in terms of both relative proportion and prevalence;
a rigorous approach to goal setting and a process of establishing targets with multiple levels of performance, which mitigate excessive risk-taking that could harm Enbridge’s value or reward poor judgment of executives;
compensation programs that include a combination of short-, medium- and long-term elements that ensure executives are incentivized to consider both the immediate and long-term implications of their decisions;
program provisions where executives are compensated for their short-term performance using a combination of safety, system reliability, environmental, financial, and customer and employee metrics that ensure a balanced perspective and are a mix of both leading (proactive/preventative) and lagging (incident-based) indicators;
performance thresholds that include both minimum and maximum payouts;
stock award programs that vest over multiple years and are aligned with overall corporate performance that drives superior value to Enbridge shareholders;
share ownership guidelines that ensure executives have a meaningful equity stake in Enbridge to align their interests with those of Enbridge shareholders;
an anti-hedging policy to prevent activities that would weaken the intended
pay-for-performance
link and alignment with Enbridge shareholders’ interests; and
an incentive compensation clawback policy that allows Enbridge to recoup overpayments made to executives in the event of fraudulent or willful misconduct.
41

The HRC Committee has considered the concept of risk as it relates to the compensation programs and has concluded that the programs do not encourage excessive or inappropriate risk-taking and are aligned with the long-term interests of shareholders.
Anti-hedging policy
Enbridge’s insider trading and reporting guidelines, among other things, prohibit directors, officers, employees and contractors (of Enbridge and its subsidiaries) from purchasing financial instruments that are designed to hedge or offset a decrease in market value of equity securities granted as compensation or held by the NEO, as such positions delink the intended alignment of employee and shareholder interests. The following activities are specifically prohibited:
any form of hedging activity;
any form of transaction involving stock options (other than exercising options in accordance with the incentive plans);
any other form of derivative trading (including “puts” and “calls”); and
“short-selling” (selling securities that the individual does not own).
Clawback policy
The incentive compensation clawback policy allows Enbridge to recover, from current and former executives, certain incentive compensation amounts awarded or paid to individuals if the individuals engaged in fraud or willful misconduct that led to inaccurate financial results reporting, regardless of whether the misconduct resulted in a restatement of all or a part of Enbridge’s financial statements.
Annual decision-making process
The HRC Committee reviews and approves the compensation plans and pay levels for all the NEOs except the President & CEO. The HRC Committee reviews and recommends the compensation plans and pay level for the President & CEO to the Board.
The chart below shows the process by which compensation decisions are made.

42

Benchmarking to peers
Total direct compensation for the NEOs is managed within a framework that involves input from and consideration by the President & CEO and the HRC Committee, with Mercer providing independent advisory support. The competitiveness of this framework is based on peer group market data extracted from third-party compensation surveys and publicly disclosed executive compensation information for comparable benchmark roles at peer companies. The market data is considered from several perspectives including organization size and industry sector (pipeline, energy and utility criteria).
As the responsibilities of Enbridge’s NEOs are primarily North American in scope, a North American peer group is determined and used for executive compensation benchmarking.
Peer group determination
The following outlines Enbridge’s compensation benchmarking peer group determination criteria:
Industry (typically defined as
low-risk
regulated operations in the energy sector) remains a key criterion for identifying peers, as that will help to ensure Enbridge can pay competitively against
“best-in-class”
companies whose executives are often the most knowledgeable about Enbridge’s core businesses.
Size/complexity remains important but is more broadly defined to consider multiple dimensions, including
GLOSSARY
financial (e.g., market capitalization, cash flow, capital employed) and nonfinancial measures (e.g., geography and breadth of operations).
Geography is not a major factor; in particular, Enbridge believes it is less important to focus on Canadian companies if they are not sufficiently comparable to Enbridge in terms of industry and/or size/complexity.
Based on these criteria, Enbridge uses a single peer group of Canadian and U.S. companies to reflect Enbridge’s identity as a North American leader that happens to be based in Canada. Our peer group of energy and infrastructure companies is weighted heavily towards the U.S. as the U.S. market offers more comparable peers from an industry and/or size/complexity perspective. It is important to note that Enbridge limits the peer group to those in the energy and infrastructure space, rather than extending to other capital-intensive sectors, as these companies are subject to the same external industry pressures and macroeconomic factors as Enbridge.
Our peer group contains companies that are generally similar in size to Enbridge, primarily in terms of enterprise value, and secondarily market capitalization and assets; size constraints were relaxed in certain instances to include those similar to Enbridge in terms of operational profile.
Enbridge’s compensation benchmarking peer group is reviewed annually by the HRC Committee. The peer group used for determining compensation in 2020 was unchanged from 2019.
  2020 compensation peer group
Canadian National Railway Company
NextEra Energy Inc.
Canadian Natural Resources Limited
Occidental Petroleum Corporation
Chevron Corporation
Phillips 66
Conoco Phillips
Schlumberger Limited
Dominion Resources Inc.
Suncor Energy Inc.
Duke Energy Corporation
The Southern Company
Energy Transfer Partners, L.P.
The Williams Companies Inc.
Enterprise Products LP
TC Energy Corporation
Halliburton Company
Union Pacific Corporation
Kinder Morgan Inc.
Setting compensation targets
Enbridge targets overall total direct compensation at the median (including the President & CEO position), considering the skills, competencies and experience of each senior executive.
Share ownership
It is important for the NEOs to have a meaningful equity stake in Enbridge. Owning Enbridge shares is a tangible way to align the interests of executives with those of Enbridge shareholders.
Executives can acquire Enbridge shares by participating in the employee savings plan, exercising stock options or by making personal investments in Enbridge shares. Personal holdings, and Enbridge shares held in the name of a spouse, dependent child or trust, all count toward meeting the guidelines. PSUs, unvested RSUs and unexercised stock options do not count toward meeting the guidelines (resulting in a more stringent threshold than typical practice).
43

The share ownership requirement is six times base salary for the President & CEO and three times base salary for the other NEOs. The NEOs have until January 1, 2022 to comply with their increased target, with the
exception of Mr. Gruending who has four years from his appointment to Executive Vice President & CFO. All have already met or exceeded the requirement, as noted in the following graph.
Target and actual share ownership as of December 31, 2020

44

Executive compensation tables and other compensation disclosures
2020 summary compensation table
The table below shows the total amounts that Enbridge and its subsidiaries paid and granted to the NEOs for the years ended December 31, 2020, 2019 and 2018. Amounts represented below for Mr. Yardley were originally paid in U.S. dollars and have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740, US$1 = C$1.2967, and US$1 = C$1.3657 for 2020, 2019 and 2018, respectively.
Name and
principal position
1
Year
Salary
($)
Stock-
based
awards
2

($)
Option-
based
awards
3

($)
Non-
equity
incentive
plan
compen-
sation
4

($)
Pension
value
5

($)
All other
compen-
sation
6

($)
Total
($)
Al Monaco
President & Chief Executive Officer
 2020 1,546,139 8,475,960 2,303,250 3,205,919 1,462,000 61,568 17,054,836
 2019 1,592,878 6,129,560 3,327,732 3,687,712 3,195,000 60,502 17,993,384
 2018 1,479,450 4,439,868 2,777,446 3,473,453 1,141,000 68,509 13,379,726
Colin K. Gruending
Executive Vice President & Chief Financial Officer
 2020 587,074 1,680,385 456,525 761,904 1,017,000 12,032 4,514,919
 2019 467,122 1,225,912 316,315 583,360 1,498,000 25,460 4,116,169
 2018 361,656 496,675 172,549 338,078 421,000 231,272 2,021,230
John K. Whelen
Former Executive Vice President
 2020 542,492 2,052,101 557,550 690,766 525,000 73,105 4,441,015
 2019 635,849 1,604,385 870,883 821,199 645,000 17,568 4,594,884
 2018 619,500 1,244,477 758,499 886,132 126,000 33,466 3,668,074
William T. Yardley
Executive Vice President & President, Gas Transmission & Midstream
 2020 700,018 2,320,853 598,335 849,262 396,000 32,065 4,896,533
 2019 732,029 3,828,546 1,069,747 767,701 351,400 32,993 6,782,416
 2018 751,161 1,570,650 847,539 968,697 359,000 32,958 4,530,005
Vern D. Yu
Executive Vice President & President, Liquids Pipelines
 2020 616,801 1,821,821 495,038 703,893 1,177,000 22,579 4,837,131
 2019 564,541 1,424,276 773,196 711,996 1,478,000 22,648 4,974,657
 2018 450,000 723,196 440,752 900,000 122,000 29,030 2,664,978
Robert R. Rooney
Executive Vice President & Chief Legal Officer
 2020 557,394 1,593,583 433,163 634,091 349,000 18,167 3,585,397
 2019 564,541 1,139,225 618,565 689,992 286,000 10,283 3,308,606
 2018 550,000 883,759 538,734 729,299 236,000 20,742 2,958,534
1
Mr. Whelen retired effective November 15, 2020.
2
The amounts disclosed in this column include the aggregate grant date fair value of PSUs and RSUs granted in 2020, 2019 and 2018. These amounts are calculated by multiplying the number of performance and restricted stock units by the unit values in the table below:
  Year granted
  
            C$            
  
            US$            
  2020
  
51.06
   
 
38.75
  2019
  
48.81
   
 
36.97
  2018
  
43.99
   
 
38.59
In May 2019, Mr. Yardley was granted 40,421 RSUs with grant date fair value of US$37.11.
3
The amounts in this column represent the grant date fair value of stock option awards granted to each of the NEOs. The grant date fair value of stock option awards is measured using the Black-Scholes option-pricing model, based on the following assumptions:
  
February 2020
 
February 2019            
 
        February 2018            
  Assumptions
 
          C$          
 
          US$          
 
          C$          
 
          US$          
 
          C$          
 
          US$          
  Expected option term
 
6 years
 
6 years
 
6 years
 
6 years
 
6 years
 
6 years
  Expected volatility
 
17.587%
 
20.283%
 
18.318%
 
21.802%
 
21.077%
 
21.893%
  Expected dividend yield
 
5.847%
 
5.847%
 
5.961%
 
5.961%
 
6.377%
 
6.377%
  Risk free interest rate
 
1.314%
 
1.416%
 
1.615%
 
2.333%
 
2.088%
 
2.694%
  Exercise price
 
$55.54
 
$41.97
 
$48.30
 
$36.71
 
$43.02
 
$33.97
  Option value
 
$3.75
 
$3.64
 
$4.03
 
$4.07
 
$3.82
 
$3.40
4
The amounts disclosed in this column represent amounts paid under the Enbridge Inc. STIP with respect to the 2020, 2019 and 2018 performance years.
5
The pension values are equal to the compensatory change shown in the defined benefit plan table.
45

6
The table below describes the elements comprising the amounts presented in this column for 2020:
  Executive
Matching
contribution under
retirement savings
plan
($)
Excess flexible
benefit credit
a
($)
Unused
vacation
($)
Personal use
of company
aircraft
($)
Parking
($)
Other benefits
b
($)
Total
($)
  Al Monaco
-40,854-7,8656,1086,74161,568
  Colin K. Gruending
-7,232--4,800-12,032
  John K. Whelen
-4,24459,817-4,2004,84473,105
  William T. Yardley
21,786--8,950-1,32932,065
  Vern D. Yu
-12,083--4,8005,69622,579
  Robert R. Rooney
-11,872--4,8001,49518,167
a)
For the NEOs domiciled in Canada, flexible benefit credits are provided based on their family status and base salary. These credits can be used to purchase benefits or can be paid in cash. Participants could receive up to 2.5% of base salary in matching contributions towards their flexible benefit credits if they made contributions into their Savings Plan. This amount represents the excess flexible benefit credits paid to the NEO.
b)
Other benefits include executive medical and other incidental compensation.
Executive compensation and shareholder return
The chart below shows the value of a $100 investment made January 1, 2016 in both Enbridge common shares and the S&P/TSX Composite Index and the S&P 500 index, at the end of each of the last five years (assuming reinvestment of dividends throughout the term). It also shows the growth in average total direct compensation for the NEOs reported in the 2020 summary compensation table over the same period.
Total direct compensation includes base salary, short-term incentive award paid, and the grant value of medium- and long-term incentive awards. Average total direct compensation is taken by dividing total direct compensation from the 2020 summary compensation table by the number of named executives in any given year. The total direct compensation value for NEOs is 0.72% of our adjusted earnings of $4,894 million for 2020.
The total return on Enbridge common shares has been positive from 2016 to 2020. Average compensation paid to the NEOs has also increased over the same period.

46

Outstanding option-based and share-based awards
The table below shows the option-based and share-based awards that were outstanding on December 31, 2020. The market value of unvested or unearned awards is calculated based on C$40.71 per share for awards denominated in Canadian dollars and US$31.99 for awards denominated in U.S. dollars, the closing prices of our shares on the TSX and NYSE on December 31, 2020. The grant date fair value for U.S. option grants and the market value of unvested or unearned awards denominated in U.S. dollars were each converted from U.S. dollars to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
   
Option-based awards
1
   
Share-based awards
 
    
Number of
securities
underlying
unexercised
options
(#)
   
Option
exercise
price
2
($)
   
Option
expiry
date
   
Value of
in-the-money

unexercised options
3
   
Number
of units
that
have not
vested
4 5
(#)
  
Market or
payout
value of
units not
vested
3
($)
   
Market or
value of vested
share-based
awards not
paid out or
distributed
3 6
($)
 
Named executive officer
  
Vested
($)
   
Unvested
($)
 
Al Monaco
   614,200    55.54    2/20/2030    0    0    43,966   1,789,860      
   825,740    48.30    2/21/2029    0    0    131,898   5,369,580      
   727,080    43.02    2/27/2028    0    0    141,635   5,765,960      
   584,000    55.84    2/28/2027    0    0    -   -    9,724,864 
   365,000    44.06    3/1/2026    0    0               
   196,000    59.08    3/2/2025    0    0               
   199,000    48.81    3/13/2024    0    0               
   229,000    44.83    2/27/2023    0    0               
    147,500    38.34    3/2/2022    349,575    0               
Colin K. Gruending
   121,740    55.54    2/20/2030    0    0    8,719   354,953      
   78,490    48.30    2/21/2029    0    0    26,147   1,064,428      
   45,170    43.02    2/27/2028    0    0    28,108   1,144,261      
   48,670    55.84    2/28/2027    0    0    -   -    604,577 
   64,600    44.06    3/1/2026    0    0               
   64,780    59.08    3/2/2025    0    0               
   66,500    48.81    3/13/2024    0    0               
   72,000    44.83    2/27/2023    0    0               
    69,750    38.34    3/2/2022    165,308    0               
John K. Whelen
   148,680    55.54    11/15/2025    0    0    2,772   112,848      
   216,100    48.30    11/15/2023    0    0    9,749   396,900      
   198,560    43.02   
 

11/15/2023

 

   0    0    23,432   953,936      
   152,910    55.84   
 

11/15/2023

 

   0    0    -   -    2,546,456 
   82,430    44.06   
 

11/15/2023

 

   0    0               
   109,670    59.08   
 

11/15/2023

 

   0    0               
   92,700    48.81   
 

11/15/2023

 

   0    0               
   78,550    44.83    2/27/2023    0    0               
   77,050    38.34    3/2/2022    182,609    0               
    84,000    28.78    2/14/2021    1,002,540    0               
William T. Yardley
   129,020    US41.97    2/20/2030    0    0    12,448   507,343      
   202,700    US36.71    2/21/2029    0    0    37,355   1,522,460      
   182,520    US33.97    2/27/2028    0    0    44,312   1,806,034      
   56,580    US41.64    2/28/2027    0    0    36,471
7
 
  1,486,427      
    58,941    US28.87    2/16/2026    234,292    0    -   -    2,984,853 
Vern D. Yu
   132,010    55.54    2/20/2030    0    0    9,450   384,712      
   191,860    48.30    2/21/2029    0    0    28,350   1,154,136      
   115,380    43.02    2/27/2028    0    0    32,911   1,339,789      
   93,300    55.84    2/28/2027    0    0    -   -    1,543,361 
   96,750    44.06    3/1/2026    0    0               
   82,340    59.08    3/2/2025    0    0               
   83,350    48.81    3/13/2024    0    0               
   83,250    44.83    2/27/2023    0    0               
    64,350    38.34    3/2/2022    152,510    0               
Robert R. Rooney
   115,510    55.54    2/20/2030    0    0    8,264   336,407      
   153,490    48.30    2/21/2029    0    0    24,801   1,009,654      
   141,030    43.02    2/27/2028    0    0    26,324   1,071,648      
    167,200    55.84    2/28/2027    0    0    -   -    1,886,017 
47

1
Each ISO award has a
10-year
term and vests
pro-rata
as to one fourth of the option award beginning on the first anniversary of the grant date.
2
Option exercise prices are reflected in the currency granted.
3
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London year-end exchange rate of US$1 = C$1.2740.
4
The number of PSUs and RSUs outstanding includes dividend equivalents as of December 31, 2020.
5
A performance multiplier of 1.0x has been used (PSUs only), based on achieving the target performance level as defined in the plan.
6
Reflects the payout value of the 2018 PSU grant, which vested on December 31, 2020 but will not be paid until March 2021. A performance multiplier of 1.82x is used.
7
Reflects RSUs granted on May 8, 2019 that remain outstanding, 20% of which vested on the first anniversary of the grant date, 20% and 60% of which vest on the second and third anniversaries of the grant date, respectively.
Value vested or earned in 2020
  Executive
  
Value vested during the year
  
  Value earned during the year  
 
  
Option-based awards
1 2
($)
   
Share-based awards
1 3
($)
  
Non-equity incentive plan
1 4
($)
 
  Al Monaco
   3,406,926    9,724,864   3,205,919 
  Colin K. Gruending
   321,146    832,454
5
 
  761,904 
  John K. Whelen
   888,481    2,546,456   690,766 
  William T. Yardley
   333,142    4,271,348
6
 
  849,262 
  Vern D. Yu
   704,506    1,543,361   703,893 
  Robert R. Rooney
   544,704    1,886,017   634,091 
1
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
2
The values of the option-based awards listed above are based on the following:
  Grant date
  
Grant price
   
        2020 vesting date        
   
Closing price on 2020 vesting date  
 
  2/29/2016
   $44.06    2/28/2020    $49.96 
  2/28/2017
   $55.84    2/28/2020    $49.96 
  2/28/2017
   US$41.64    2/28/2020    US$37.43 
  2/27/2018
   $43.02    2/27/2020    $50.84 
  2/27/2018
   US$33.97    2/27/2020    US$37.66 
  2/21/2019
   $48.30    2/21/2020    $55.31 
  2/21/2019
   US$36.71    2/21/2020    US$41.87 
3
Includes the 2018 PSUs, including dividend equivalents, that matured on December 31, 2020. A performance multiplier of 1.82x has been used.
4
Based on corporate, business unit and individual performance for the 2020 performance year.
5
Includes the 2018 RSUs, including dividend equivalents, that matured on December 1, 2020.
6
Includes the 2019 RSUs, including dividend equivalents, that matured on May 8, 2020.
Termination of employment and
change-in-control
arrangements
Employment agreements
Enbridge has entered into employment agreements with each of the NEOs. The terms in the employment agreements are competitive and part of a comprehensive compensation package that assists in recruiting and retaining top executive talent.
The agreements generally provide payments for executives in the case of involuntary termination for any reason (other than for cause) or voluntary termination within 150 days after constructive dismissal, as defined in each agreement, and do not provide for any “single-trigger” severance payments upon a change in control of the company. As a condition to receiving payments under the employment agreements upon a qualifying termination of employment, the executive must execute a general release of claims in favor of Enbridge and comply with the following restrictive covenants:
  Confidentiality provision
Non-competition/solicitation
No recruitment
  2 years after departure
1 year after departure2 years after departure
48

Termination of employment scenarios
Compensation that would be paid to the NEOs pursuant to the terms of their existing employment agreements under various termination scenarios is described below.
AFUDCAllowance for funds used during construction
AOCIAccumulated other comprehensive income/(loss)
AROAsset retirement obligations
ASCAccounting Standards Codification
ASUAccounting Standards Update
BCBritish Columbia
bcf/dBillion cubic feet per day
bpdBarrels per day
Type
CCSCarbon capture and storage
CERCanada Energy Regulator, created by the Canadian Energy Regulator Act which also repealed the National Energy Board Act, on August 28, 2019
CPP InvestmentsCanada Pension Plan Investment Board
CTSCompetitive Toll Settlement
DAPLDakota Access Pipeline
DawnAn extensive network of termination
Base salary
Short-term incentive
Medium-underground storage pools at the Tecumseh Gas Storage facility and long-term incentives
Pension
Benefits
Dawn Hub
DCP MidstreamDCP Midstream, LLC
EBITDAEarnings before interest, income taxes and depreciation and amortization
EEPEnbridge Energy Partners, L.P.
EIECEnbridge Ingleside Energy Center
EISEnvironmental Impact Statement
EMFÉolien Maritime France SAS
EnbridgeEnbridge Inc.
Enbridge GasEnbridge Gas Inc.
ESGEnvironment, Social and Governance
FERCFederal Energy Regulatory Commission
Flanagan SouthFlanagan South Pipeline
GHGGreenhouse gas
H2Hydrogen gas
IJTInternational Joint Tariff
ISOIncentive Stock Options
kbpdThousand barrels per day
LMCILand Matters Consultation Initiative
LNGLiquefied natural gas
MATLMontana-Alberta Tie-Line
MD&AManagement’s Discussion and Analysis
ModaModa Midstream Operating, LLC
4



MW
ResignationNonePayable in full if executive has worked the entire calendar year and remains actively employed on the payment date. Otherwise, none.
•  PSUs and RSUs forfeited.
•  Vested stock options must be exercised within 30 days of resignation or by the end of the original term (if sooner).
•  Unvested stock options are cancelled.
No longer earns service credits.NoneMegawatts
NCIBRetirementCurrent year’s incentive prorated to retirement date
•  PSUs and RSUs are prorated to retirement date and value is assessed and paid at the end of the usual term.
•  Stock options granted prior to 2020 continue to vest and can be exercised for three years after retirement (or option expiry, if sooner)
•  Stock options granted in 2020 continue to vest and can be exercised for five years after retirement (or option expiry, if sooner)
Post-retirement benefits begin.Normal course issuer bid
NGLsNatural gas liquids
NovercoNoverco Inc.
NYSENew York Stock Exchange
OBPSOutput-based pricing system
OCIOther comprehensive income/(loss)

OEB
Termination not for cause or constructive dismissalCurrent salary is paid in a lump sum (3x for CEO and 2x for other NEOs)
The average short-term incentive award over the past two years is paid out in a lump sum (3x for CEO and 2x for other NEOs)
plus
the current year’s short-term incentive, prorated based on active service during the year of termination based on target performance
•  PSUs and RSUs are prorated to date of termination (plus any applicable notice period) and value is assessed and paid at the end of the usual term.
•  Vested stock options must be exercised according to stock option terms.
•  The
in-the-money
spread value of unvested stock options is paid in cash.
Additional years of pension credit are added to the final pension calculation (three years for CEO and two years for other NEOs).Value of future benefits paid out in a lump sum (3x for CEO and 2x for other NEOs).Ontario Energy Board
OPEBTermination following a change of control (CIC)Other postretirement benefit obligations
PHMSA
•  PSUs vest
Pipeline and value is assessed and paid on performance measures deemed to have been achieved as of the change of control. RSUs vest and are paid out.
•  All stock options vest and remain exercisable for 30 days following termination (or option expiry, if sooner).
Hazardous Materials Safety Administration
49

The amounts shown in the table below include the estimated potential payments and benefits that would be payable to each of our NEOs as a result of the specified triggering event, assumed to occur as of December 31, 2020. The actual amounts that would be payable in these circumstances can be determined only at the time of the executive’s separation, would include payments or benefits already earned or vested and may differ from the amounts set forth in the table below. Amounts in U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
Named
executive
officer
1
  
Triggering event
2
 
Base
salary
3
($)
  
Short-
term
incentive
4

($)
  
Medium-
term
incentive
5

($)
  
Long-
term
incentive
6

($)
  
Pension
7
($)
  
Benefits
8
($)
  
Total
payout
($)
 
  Al Monaco
  CIC  -   -   -   -   -   -   0 
  Death  -   -   12,925,401   -   -   55,969   12,981,370 
  Retirement  -   -   5,883,086   -   -   55,969   5,939,056 
  Voluntary or for cause termination  -   -   -   -   -   55,969   55,969 
  Involuntary termination without cause  4,365,600   10,741,747   12,925,401   -   3,771,000   252,009   32,055,757 
  Involuntary or good reason termination after a CIC  4,365,600   10,741,747   12,925,401   -   3,771,000   252,009   32,055,757 
  Colin K.
  Gruending
  CIC  -   -   -   -   -   -   0 
  Death  -   -   3,707,902   -   -   22,718   3,730,620 
  Voluntary or for cause termination  -   -   -   -   -   22,718   22,718 
  Involuntary termination without cause  1,181,340   921,438   3,691,385   -   1,551,000   88,954   7,434,117 
  Involuntary or good reason termination after a CIC  1,181,340   921,438   3,691,385   -   1,551,000   88,954   7,434,117 
  John K.
  Whelen
9
  Retirement  -   -   709,308   -   -   59,817   769,125 
  William T.
  Yardley
  CIC  -   -   -   -   -   -   0 
  Death  -   -   5,322,264   -   -   25,860   5,348,124 
  Retirement  -   -   2,597,159   -   -   25,860   2,623,019 
  Voluntary or for cause termination  -   -   -   -   -   25,860   25,860 
  Involuntary termination without cause  1,344,735   2,212,254   5,298,656   -   837,000   94,914   9,787,559 
  Involuntary or good reason termination after a CIC  1,344,735   2,212,254   5,298,656   -   837,000   94,914   9,787,559 
  Vern D. Yu
  CIC  -   -   -   -   -   -   0 
  Death  -   -   2,878,638   -   -   23,649   2,902,287 
  Voluntary or for cause termination  -   -   -   -   -   23,649   23,649 
  Involuntary termination without cause  1,229,760   1,611,996   2,860,736   -   2,159,000   100,581   7,962,073 
  Involuntary or good reason termination after a CIC  1,229,760   1,611,996   2,860,736   -   2,159,000   100,581   7,962,073 
  Robert R.
  Rooney
  CIC  -   -   -   -   -   -   0 
  Death  -   -   2,417,709   -   -   20,693   2,438,402 
  Retirement  -   -   1,098,013   -   -   20,693   1,118,706 
  Voluntary or for cause termination  -   -   -   -   -   20,693   20,693 
  Involuntary termination without cause  1,076,040   1,419,291   2,402,055   -   971,000   87,933   5,956,319 
  Involuntary or good reason termination after a CIC  1,076,040   1,419,291   2,402,055   -   971,000   87,933   5,956,319 
50

1
Mr. Whelen retired on November 15, 2020.
2
Messrs. Monaco, Yardley and Rooney are the only NEOs who are retirement eligible as of December 31, 2020. Retirement eligibility under Enbridge programs means age 55 or older.
3
Reflects a lump sum payment equal to three times (for Mr. Monaco) and two times (for Messrs. Gruending, Yardley, Yu and Rooney) the NEO’s base salary in effect as at December 31, 2020.
4
Reflects a lump sum payment equal to three times (for Mr. Monaco) and two times (for Messrs. Gruending, Yardley, Yu and Rooney) the average of the short-term incentive award paid to the NEO in the two years preceding the year in which the termination occurs. In addition, the amount the NEO would receive as short-term incentive payment for the current year is reflected in the 2020 summary compensation table.
5
Represents the value of RSUs and PSUs that would vest and be settled in cash upon the triggering event, based on C$40.71 for awards granted in Canadian dollars and US$31.99 for awards granted in U.S. dollars, the closing price of an Enbridge share on the TSX and NYSE, respectively, on December 31, 2020 and assuming, in the case of PSUs, target performance. For PSUs and RSUs, severance period, as outlined in the executive employment agreement, counts towards active service when prorating for termination without cause.
6
Represents the
“in-the-money
value” of unvested ISOs as of December 31, 2020, that would be paid in cash (as a result of an involuntary termination without cause) or that would become vested (as a result of an involuntary or good reason termination after a Change in Control or retirement).
In-the-money
value is calculated as C$40.71 for awards granted in Canadian dollars and US$31.99 for awards granted in U.S. dollars, the closing price of an Enbridge share on the TSX and NYSE, respectively, on December 31, 2020, less the applicable exercise price of the option.
7
Reflects the value of three additional years of pension credit for Mr. Monaco and two additional years of pension credit for each of Messrs. Gruending, Yardley, Yu and Rooney.
8
Reflects a lump sum cash payment in respect of the flex credit allowance, vacation carryover and savings plan matching contributions that would have been paid by Enbridge in respect of the NEO over a period of three years (for Mr. Monaco) or two years (for each of Messrs. Gruending, Yardley, Yu and Rooney) following the executive’s termination, plus an allowance for financial and career counselling.
9
Amounts shown for Mr. Whelen represent the value on his departure date, with payout value of the unvested medium- and long-term incentives based on the closing price of an Enbridge share on the TSX on November 13, 2020 of $37.38.
Additional equity compensation information
Enbridge shares used for purposes of equity compensation
Enbridge has two “prior stock option plans” which were approved by Enbridge shareholders in 2007, as follows:
Enbridge Inc. Incentive Stock Option Plan (2007), as revised (“Incentive stock option plan”); and
Enbridge Inc. Performance Stock Option Plan (2007), as amended and restated (2011) and further amended (2012 and 2014) (“Performance stock option plan”).
The Performance stock option plan was historically used to grant options, but no options have been granted under it since 2014.
Enbridge adopted the 2019 LTIP effective February 13, 2019, under which stock options were granted beginning in 2019. Beginning in 2020, share-settled RSUs were granted under the 2019 LTIP. The 2019 LTIP was approved by our shareholders at our 2019 annual meeting of shareholders. No further awards have been or will be granted under the Incentive stock option plan or Performance stock option plan after February 13, 2019, and all shares still available to be issued and not subject to awards under these prior stock option plans became available under the 2019 LTIP.
Shares reserved for equity compensation as of December 31, 2020
   
A
  
B
  
C
 
Plans approved by
security holders
 
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(#)
  
Weighted-average exercise price

of outstanding options, warrants
and rights
($)
  
Number of securities remaining
available for future issue under
equity compensation plans
(excluding securities reflected
in column A)
(#)
 
2019 LTIP
  11,683,418   50.91
3 4
 
  38,016,582             
Prior stock option plans
1
  24,146,312   48.82
3
 
  —               
Spectra 2007 LTIP
2
  775,806   36.78
3
 
  —               
           
1.8770% of total issued and
outstanding Enbridge shares
 
 
1
Includes 24,146,312 options outstanding under the Incentive stock option plan and no options outstanding under the Performance stock option plan.
2
Awards granted under the Spectra 2007 LTIP were assumed by Enbridge at the closing of the Merger Transaction, as described in the “Assumed equity-based compensation awards from Spectra Energy” section. No further awards have been or will be granted under the Spectra 2007 LTIP following the closing of the Merger Transaction.
3
U.S. dollars have been converted to Canadian dollars using the published WM/Reuters 4 pm London
year-end
exchange rate of US$1 = C$1.2740.
4
This weighted-average exercise price relates only to options granted under the 2019 LTIP. All other awards granted under the 2019 LTIP are deliverable without the payment of any consideration, and therefore these awards have not been considered in calculating the weighted average exercise price.
51

Awards granted and outstanding as of December 31, 2020
Awards outstanding
  
# outstanding
   
% of total issued and
outstanding Enbridge shares
 
2019 LTIP
   11,683,418    0.5768 
Incentive stock option plan
   24,146,312    1.1922 
Performance stock option plan
   0    0.0000 
Spectra 2007 LTIP – stock options
1
   775,806    0.0383 
1
Awards granted under the Spectra 2007 LTIP as described in the “Assumed equity-based compensation awards from Spectra Energy” section.
Plan restrictions – 2019 LTIP
PSUPerformance Stock Units
Enbridge shares reserved for issue under the 2019 LTIPRNG
49,700,000 in total, or 2.45% of Enbridge’s total issued and outstanding Enbridge shares as of December 31, 2020.
The total number of Enbridge shares reserved for issuance to Insiders pursuant to all security based compensation arrangements of the company shall not exceed 10% of the number of Enbridge shares outstanding at the time of reservation.
Renewable natural gas
ROURight-of-use
Enbridge shares that can be issued in a
one-year
period
RSU
The total number of Enbridge shares issued to Insiders pursuant to all security based compensation arrangements of the company shall not exceed 10% of the number of Enbridge shares outstanding at the time of issuance (excluding any other Enbridge shares issued under all security based compensation arrangements of the company during such
one-year
period)
Restricted Stock Units
Sabal TrailSabal Trail Transmission, LLC
The number of Enbridge shares that can be issued as incentive stock options (within the meaning of the U.S. Internal Revenue Code)Seaway PipelineUp to 2,000,000 Enbridge shares can be issued under the 2019 LTIP as incentive stock options.Seaway Crude Pipeline System
SEPSpectra Energy Partners, LP
Stock options delivered to a greater than 10% shareholderSpectra EnergyIf an Incentive Stock Option is granted to a greater than 10% shareholder, the grant price will not be less than 110% of the fair market value on the grant date of the Incentive Stock Option, and in no event will such Incentive Stock Option be exercisable after the expiration of five years from the date on which the Incentive Stock Option is granted.Spectra Energy Corp
Minimum vesting
All awards shall be subject to a minimum vesting schedule of at least twelve months following the date of grant of the award, provided that vesting may accelerate in connection with death, retirement, a change in control or other termination of service.
Notwithstanding the foregoing, up to 5% of the Enbridge shares available for grant under the 2019 LTIP may be granted with a minimum vesting schedule that is shorter than twelve months.
Annual burn rate
Awards outstanding
 
                    2020                    
 
                    2019                    
 
                    2018                    
2019 LTIP
 0.2529% 0.3348% —  
Incentive stock option plan
1
 —   —   0.3350%
Performance stock option plan
2
 —   —   —  
Spectra 2007 LTIP – stock options
3
 —   —   —  
1
No grants have been made under this plan since 2018.
2
No grants have been made under this plan since 2014.
3
All grants under the Spectra 2007 LTIP were made by Spectra Energy prior to the Merger Transaction. No further awards have been or will be granted under the Spectra 2007 LTIP following the closing of the Merger Transaction.
52

Making changes to the 2019 LTIP
To the extent permitted by applicable laws, the Board may amend, suspend or terminate the 2019 LTIP at any time without shareholder approval, provided that no amendment, other than an increase to the overall share limit, may materially and adversely affect any award outstanding at the time of the amendment without the affected participant’s consent.
Enbridge shareholder approval is required to implement any of the following changes:
increasing the overall share limit;
reducing the grant, exercise or purchase price for any awards;
the cancellation of any awards and the reissue of or replacement of such awards with awards having a lower grant, exercise or purchase price;
removing or exceeding the limits of the 2019 LTIP on participation by insiders;
the extension of the term of any award;
allowing other than employees or
non-employee
directors of the company or a subsidiary to become participants in the 2019 LTIP;
allowing awards to become transferable or assignable other than by will or according to the laws of descent and distribution; and
changing the amendment provisions of the 2019 LTIP.
Termination provisions of equity compensation plans
The termination provisions for equity compensation awards granted under the 2019 LTIP (as governed by the incentive stock option grant agreements and the RSU grant agreements), the incentive stock option plan (2007), as revised, and the performance stock option plan, are summarized below.
SPOTSea Port Oil Terminal
Reason for termination
Incentive stock option provisions
1
Restricted stock unit provisions
Texas EasternTexas Eastern Transmission, L.P.
Resignation
Can exercise vested options up to 30 days from the date of termination or until the option term expires (if sooner).All outstanding RSUs are forfeited.
Retirement
For incentive stock options granted prior to 2020, options continue to vest and can be exercised up to three years from retirement or until the stock option term expires (if sooner).
For incentive stock options granted in 2020 and thereafter, options continue to vest and can be exercised up to five years from retirement or until the stock option term expires (if sooner).
Conditions for performance stock options are mentioned below.
RSUs are prorated to retirement date and value is assessed and settled at the end of the usual term.
Death
All options vest and can be exercised up to 12 months from the date of death or until the option term expires (if sooner).All outstanding RSUs become vested and are settled no later than 30 days following the date of death.
Disability
Options continue to vest based on the regular provisions of the plan.All outstanding RSUs become vested and are settled no later than 30 days following the date of disability.
Involuntary
termination
not for causeUnvested options continue to vest during the notice period, and options that are vested or become vested can be exercised up to 30 days after the notice period expires or until the option term expires (if sooner).RSUs are prorated to termination date (plus any applicable notice period) and value is assessed and settled at the end of the usual term.
for causeAll options are cancelled on the date of termination.All outstanding RSUs are forfeited.
53

Reason for termination
TSX
Incentive stock option provisions
1
Restricted stock unit provisions
Toronto Stock Exchange
ChangeUS
United States of control or
reorganization
America
US GAAP
Beginning withGenerally accepted accounting principles in the 2017 grants, if the employmentUnited States of a participant is terminated without cause (including constructive dismissal) by the company or a subsidiary within two years after a change of control, then all unvested optionsAmerica
US L3R ProgramUnited States portion of the participant vest on that double-trigger date.
For 2016 and prior grants, for a change of control, options vest on a date determined by the HRC Committee before the change of control. For any other kind of reorganization, options are to be assumed by the successor company. If they are not assumed, they will vest and the value will be paid in cash.
Performance stock option plan
: For a change of control, options vest on a date determined by the HRC Committee before the change of control.
If the employment of a participant is terminated without cause, (including constructive dismissal) by the company or a subsidiary within two years after a change of control, then all outstanding RSUs become vested and are settled no later than 30 days following the date of termination.
Line 3 Replacement Program
Other transfer or assignment of awardsThe holder of an option may not transfer or assign it other than by will, or as allowed by the laws of descent and distribution.The award may not be sold, pledged, assigned, hypothecated, transferred, or disposed of in any manner other than by will or by the laws of descent or distribution.
1
Differences in termination provisions apply for US$ options where the executive has elected treatment as incentive stock options within the meaning of U.S. Internal Revenue Code Section 422.
Options granted under the Performance stock option plan have the same termination provisions as options granted under the Incentive stock option plan, except for the following differences:
for retirement, performance stock options are prorated for the period of active employment in the five-year period starting January 1 of the year of grant. These options can be exercised until the later of three years after retirement, or 30 days after the date by which the share price targets must be met (or the date the option expires, if earlier), as long as the share price targets are met;
for death, unvested performance stock options are prorated and the plan assumes performance requirements have been met;
for involuntary termination
not-for-cause,
unvested performance stock options are prorated; and
for change of control, the plan assumes the performance requirements have been met and the plan was not amended in 2018 to implement a double trigger change of control as there are currently no plans to grant further awards under the plan.
Assumed equity-based compensation awards from Spectra Energy
Pursuant to the terms of the merger agreement, Enbridge assumed all awards outstanding under the Spectra Energy Corp 2007 Long Term Incentive Plan, as amended and restated (the “Spectra 2007 LTIP”) at the closing of the Merger Transaction (“Assumed Spectra LTIP Awards”). The Assumed Spectra LTIP Awards, including the shares of Enbridge issuable thereunder, were approved by Enbridge shareholders as part of the Merger Transaction on December 15, 2016. No further awards have been or will be granted under the Spectra 2007 LTIP following the closing of the Merger Transaction.
Spectra 2007 LTIP
The Assumed Spectra LTIP Awards remain subject to and will continue to be administered by Enbridge pursuant to the terms of Spectra 2007 LTIP. The following summarizes the material provisions of the Spectra 2007 LTIP to the extent applicable to the Assumed Spectra LTIP Awards. The summary is qualified in its entirety by the full text of the amended and restated Spectra 2007 LTIP, which is available on Enbridge’s profile on the SEC’s website at www.sec.gov.
General provisions
Number of shares. The aggregate number of Enbridge shares that may be issued pursuant to the Assumed Spectra LTIP Awards is 5,000,000 shares of Enbridge representing 0.25% of Enbridge’s outstanding and issued shares as at December 31, 2019.
Reservation of shares. When Spectra Energy first adopted the Spectra 2007 LTIP in 2007, it reserved 30,000,000 shares of common stock for issuance under the Spectra 2007 LTIP, with an additional 10,000,000 shares and 12,500,000 shares reserved following shareholder approval on April 19, 2011 and April 26, 2016, respectively. Immediately prior to closing of the Merger Transaction, there were 19,756,580 shares of Spectra Energy common stock available for future issuance under the Spectra 2007 LTIP. However, Enbridge determined that it would not grant any additional awards under the Spectra 2007 LTIP following the closing of the Merger Transaction and as a result, assumed only those shares issuable under the Assumed Spectra LTIP Awards. All future equity-based awards granted by Enbridge (including those made to legacy Spectra Energy employees) will be awarded pursuant to Enbridge’s existing plans and not the Spectra 2007 LTIP.
54

Administration. Prior to the closing of the Merger Transaction, the Spectra 2007 LTIP was administered by the Compensation Committee of Spectra Energy, which had the authority to determine the persons to whom awards were granted, the types of awards granted, the time at which awards were to be granted, the number of shares, units or other rights subject to an award, and the terms and conditions of each award. Following the completion of the Merger Transaction, the Spectra 2007 LTIP will, solely to the extent applicable to the Assumed Spectra LTIP Awards, be administered by the HRC Committee consistent with the administration of Enbridge’s existing compensation programs.
Eligibility. All key employees of Spectra Energy and its subsidiaries and all
non-employee
directors were eligible for awards granted under the Spectra 2007 LTIP, as selected from time to time by the Compensation Committee of Spectra Energy in its sole discretion. As noted above, only those shares issuable under the Assumed Spectra LTIP Awards were assumed by Enbridge in connection with the Merger Transaction and as a result, no additional awards will be granted by Enbridge to any individual under the Spectra 2007 LTIP.
Awards. As described in more detail below, the Assumed Spectra LTIP Awards include:
Spectra Energy options;
Spectra Energy phantom units;
Spectra Energy PSUs; and
Dividend equivalent awards.
Adjustments to awards. The HRC Committee may determine and implement appropriate adjustments to the Assumed Spectra LTIP Awards in the event of any merger, consolidation, recapitalization, reclassification, stock dividend, stock split or other similar change of control transactions.
Term and amendment. The Spectra 2007 LTIP has a term of ten years from the date of approval by the shareholders of Spectra Energy, which was last granted on April 26, 2016, subject to earlier termination or amendment in accordance with the terms of the Spectra 2007 LTIP. Any amendment to the Assumed Spectra LTIP Awards or the Spectra 2007 LTIP that is implemented by the HRC Committee may not materially adversely affect the Assumed Spectra LTIP Awards without consent of the holder of such award.
Assignability. A stock option granted under the Spectra 2007 LTIP may, solely to the extent permitted by the HRC Committee, be transferred to members of the participants’ immediate family or to trusts, partnerships or corporations whose beneficiaries, members or owners are members of the participant’s immediate family or such other person as may be approved by the HRC Committee in advance and set forth in the award agreement. All other Assumed Spectra LTIP Awards are not assignable or transferable except by will or the laws of descent and distribution.
Stock options
Nonqualified stock options and incentive stock options. Spectra Energy granted options under the Spectra 2007 LTIP to purchase shares of Spectra Energy common stock (“Spectra Energy options”) to certain of its employees. As
of immediately prior to the closing of the Merger Transaction, there were 4,000 Spectra Energy options outstanding under the Spectra 2007 LTIP at a weighted average exercise price of US$26.33 per share of Spectra Energy common stock and 892,163 Spectra Energy options outstanding under the Spectra 2007 LTIP at a weighted average exercise price of US$28.40 per share of Spectra Energy common stock.
Exercise price. The exercise price of each Spectra Energy option was determined by the Compensation Committee of Spectra Energy at the date of grant, provided however, that the exercise price per option could not be less than 100% of the fair market value per share of the common stock of Spectra Energy as of the date of grant. As the exercise price of the Spectra Energy options was determined at the date of grant, the exercise price may be below the then current market price of the Enbridge shares at the time the options are exercised.
Vesting and term of stock options. The Compensation Committee of Spectra Energy prescribed in the award agreement applicable to each Spectra Energy option the time or times at which, or the conditions upon which, such option vests or becomes exercisable. Spectra Energy options generally have a term of ten years from date of grant and during such term, once vested, the option could be exercised, unless a shorter exercise period was specified by the Compensation Committee of Spectra Energy in an award agreement, and subject to such limitations as may apply under an award agreement relating to the termination of a participant’s employment or other service with Spectra Energy or any of its subsidiaries.
Treatment upon closing of the Merger Transaction. At the closing of the Merger Transaction, each outstanding Spectra Energy option, whether vested or unvested, was automatically converted into an option to purchase, on the same terms and conditions as were applicable immediately prior to the closing, the number of Enbridge shares equal to the product (rounded down to the nearest whole number) of (i) the number of shares of Spectra Energy common stock subject to such option immediately prior to the closing and (ii) 0.984 (“Exchange Ratio”), at an exercise price per share (rounded up to the nearest whole cent) equal to (A) the exercise price per share of Spectra Energy common stock of such Spectra Energy option immediately prior to the closing divided by (B) the Exchange Ratio. The Spectra Energy options assumed by Enbridge in connection with the Merger Transaction are exercisable for 881,819 Enbridge shares at a weighted average exercise price of US$28.86 per share of Enbridge shares, vest at various dates until February 2019 and have various terms expiring on or before February 2026.
Phantom stock units
Grant, price and vesting. Spectra Energy granted awards of phantom units under the Spectra 2007 LTIP (“Spectra Energy phantom units”) which entitle the holder thereof the right to receive at the end of a fixed vesting period, payment based on the value of a share of common stock at the time of vesting. On the applicable vesting dates, Spectra Energy phantom units are settled in Enbridge shares or cash with an equivalent fair market value as required by the terms of such award.
55

Treatment upon closing of the Merger Transaction. At the closing of the Merger Transaction, each Spectra Energy phantom unit, whether vested or unvested, was automatically converted into a phantom unit, on the same terms and conditions as were applicable immediately prior to the closing, denominated in a number of Enbridge shares equal to the product (rounded down to the nearest whole number) of (i) the number of shares of Spectra Energy common stock subject to such Spectra Energy phantom unit immediately prior to the closing and (ii) the Exchange Ratio. Enbridge assumed 1,566,726 Spectra Energy phantom units which were converted into 1,541,094 phantom units denominated in Enbridge shares in connection with the Merger Transaction. Approximately 42% of these assumed Spectra phantom units will be settled in Enbridge shares and approximately 58% will be settled in cash at various dates until February 2020.
Performance awards
Grant. Spectra Energy granted certain performance awards denominated in shares of Spectra Energy common stock under the Spectra 2007 LTIP (“Spectra Energy PSUs”) which become payable at the completion of a three-year performance period based upon the achievement of certain performance criteria established by the Compensation Committee of Spectra Energy. Performance award payments made in the form of Enbridge shares are valued at their fair market value at the time of payment.
Treatment upon closing of the Merger Transaction – 2015 Spectra Energy PSUs. At the closing of the Merger Transaction, each outstanding Spectra Energy PSU granted in the 2015 calendar year (“2015 Spectra Energy PSU”), was automatically cancelled and converted into the right to receive a number of Enbridge shares equal to the product (rounded down to the nearest whole number) of (i) the number of shares of Spectra Energy common stock subject to such 2015 Spectra Energy PSU immediately prior to the closing multiplied by (ii) the Exchange Ratio, together with a cash payment equal to the amount of any dividend equivalents accrued with respect to such 2015 Spectra Energy PSU. The number of shares of Spectra Energy common stock subject to such 2015 Spectra Energy PSU was determined assuming a vesting percentage determined as set forth in the applicable award agreement (which was based upon Spectra Energy’s total stockholder return relative to the total stockholder return of the peer group for the period beginning on January 1, 2015, and ending on the date on which the closing of the Merger Transaction occurred). Approximately 820,671 Enbridge shares and US$2,637,494 in respect of accrued dividend equivalents (in each case, before tax withholding) were payable to holders of 2015 Spectra Energy PSUs in connection with the closing of the Merger Transaction.
Treatment upon closing of the Merger Transaction – 2016 Spectra Energy PSUs. At the closing of the Merger Transaction, each outstanding Spectra Energy PSU granted in the 2016 calendar year (“2016 Spectra Energy PSU”), was automatically converted into a
service-based stock unit denominated in Enbridge shares and subject to the same terms and conditions (including service vesting terms, but excluding any performance vesting terms) as were applicable to the underlying 2016 Spectra Energy PSU prior to the closing. The number of Enbridge shares subject to each such stock unit is equal to the product (rounded down to the nearest whole number) of (i) the number of shares of Spectra Energy common stock subject to such 2016 Spectra Energy PSU immediately prior to the closing (with any performance-based vesting conditions deemed satisfied based on actual performance through the closing) multiplied by (ii) the Exchange Ratio. In connection with the Merger Transaction, Enbridge assumed 560,656 2016 Spectra Energy PSUs which, after application of the performance multiplier, were converted into 1,103,132 stock units denominated in Enbridge shares. As assumed, these stock units will be settled in Enbridge shares generally after the December 31, 2018 vesting date.
Other stock-based awards
Other stock-based awards. In addition to the Assumed Spectra LTIP Awards, Spectra Energy had other equity-based or equity-related awards representing a right to acquire or receive shares of Spectra Energy common stock or payments or benefits measured by the value thereof (“Spectra Energy other awards”) outstanding under the Spectra Energy Executive Savings Plan and the Spectra Energy Directors’ Savings Plan (“Spectra Savings Plans”).
Treatment upon closing of the Merger Transaction. At the closing of the Merger Transaction, each outstanding Spectra Energy other award was automatically converted into a right to acquire or receive benefits measured by the value of Enbridge shares, on the same terms and conditions as were applicable to the Spectra Energy other award immediately prior to the closing. As converted, the number of Enbridge shares subject to such other award is equal to the product (rounded down to the nearest whole number) of (i) the number of shares of Spectra Energy common stock subject to such award immediately prior to the closing and (ii) the Exchange Ratio. The Spectra Savings Plans have trust funding vehicles (commonly referred to as rabbi trusts) (“Spectra Savings Plan Trusts”). Obligations to fund the Spectra Savings Plan Trusts were triggered in connection with the Merger Transaction. For any share-settled Spectra Energy other awards, the Enbridge shares used to settle such awards will be obtained on the market by the trustee of the Spectra Savings Plan Trusts.
Dividend equivalent awards
Dividend equivalent awards. Dividend equivalent awards granted under the Spectra 2007 LTIP entitled the holder to a right to receive cash payments determined by reference to dividends declared on Spectra Energy common stock during the term of the award.
56

Quantification of equity-based compensation
As of December 31, 2020, there is an aggregate of 775,806 Enbridge shares issuable in connection with the outstanding Assumed Spectra LTIP Awards, representing approximately 0.0383% of Enbridge’s issued and outstanding shares. Set forth below are the number of Enbridge shares issuable under the Spectra 2007 LTIP in connection with the exercise or settlement of the Assumed Spectra Energy Awards outstanding as of December 31, 2020.
Spectra Energy options
 
Spectra Energy
phantom units
 
Total Enbridge shares
issuable under
Spectra 2007 LTIP
 
Percentage of issued and
outstanding Enbridge shares
775,806
 0 775,806 0.0383%
Termination provisions of Spectra Energy options, Spectra Energy phantom units, and Spectra Energy PSUs
The termination provisions for the Spectra Energy options, Spectra Energy phantom units, and Spectra Energy PSUs are described below.
VIE
  Reason for termination
Provisions
Voluntary termination
(not retirement eligible)
The unvested portion of such an award terminates immediately.
Vested Spectra Energy options can be exercised through the earlier of 3 months following termination of employment or the 10th anniversary of the grant date.
Voluntary termination
(retirement eligible)
The award is
pro-rated
based on full and partial months of service during the vesting period, and the
pro-rated
award becomes payable on the original vesting date.
Vested Spectra Energy options can be exercised through the 10th anniversary of the grant date.
Involuntary termination, for cause
The unvested portion of such an award terminates immediately.
Vested Spectra Energy options can be exercised through the earlier of 3 months following termination of employment or the 10th anniversary of the grant date.
Involuntary termination, without cause or for good reason before 2 year anniversary of change in control (the
2-Year
CIC Period)
The unvested portion of such an award vests upon such termination from employment.
Vested Spectra Energy options can be exercised through the 10th anniversary of the grant date.
Involuntary termination, without cause after
2-Year
CIC Period
The award is
pro-rated
based on full and partial months of service during the vesting period.
Spectra Energy PSUs – The
pro-rated
award becomes payable on the original vesting date.
Spectra Energy phantom units – The
pro-rated
award becomes payable upon such termination from employment.
Vested Spectra Energy options can be exercised through the earlier of 3 months following termination of employment or the 10th anniversary of the grant date.
Employment termination as a result of death or disability
The unvested portion of such an award vests.
Vested Spectra Energy options can be exercised through the earlier of 36 months following such termination of employment or the 10th anniversary of the grant date.
Other transfer or assignment of stock options
The holder of an option may not transfer or assign it other than by will, or as allowed by the laws of descent and distribution. The Spectra Energy phantom units and Spectra Energy PSUs are not assignable or transferable by the holder of the award.
57

Treatment of Assumed Spectra LTIP Awards post-Merger Transaction
Pursuant to the terms of the Spectra 2007 LTIP, the Assumed Spectra LTIP Awards will vest in the event that, the holder of such award experiences a qualifying termination within 24 months following the completion of the Merger Transaction. Under the Spectra 2007 LTIP, a qualifying termination generally includes an involuntary termination of the holder of such award by Enbridge without cause or by the holder with good reason.
Report of the Human Resources & Compensation Committee
The Human Resources & Compensation Committee has reviewed and discussed the preceding Compensation Discussion and Analysis with management. Based on the review and discussion, the Human Resources & Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in the Circular. This report is provided by the following independent directors who comprise the Human Resources & Compensation Committee:
V. Maureen Kempston Darkes (Chair)
Pamela L. Carter
Marcel R. Coutu
Susan M. Cunningham
Gregory J. Goff
58

Director compensation
Philosophy and approach
The Board is responsible for developing and implementing the Directors’ Compensation Plan and has delegated the
day-to-day
responsibility for director compensation to the Governance Committee.
Our Directors’ Compensation Plan is designed with four key objectives in mind:
to attract and retain the most qualified individuals to serve as directors;
to compensate our directors to reflect the risks, responsibilities and time commitment they assume when serving on our Board and Board committees;
to offer directors compensation that is competitive with other public companies that are comparable to Enbridge and to deliver such compensation in a tax effective manner; and
to align the interests of directors with those of our shareholders.
While our executive compensation program is designed around pay for performance, director compensation is based on annual retainers. This is to meet the compensation objectives and to help ensure our directors are unbiased when making decisions and carrying out their duties while serving on our Board.
The Governance Committee uses a peer group of companies to set the annual retainers for our Board and targets director compensation at or about the 50th percentile. See “Benchmarking to peers” beginning on page 43 for more information about our peer group and how we benchmark executive compensation.
The Governance Committee reviews the Directors’ Compensation Plan every year, with assistance from management. Every second year a formal review by an external consultant is undertaken. Each year, as part of this review, the Governance Committee considers the time commitment and experience required of members of our Board and the director compensation paid by a group of comparable public companies when it sets the compensation. The Governance Committee also reviews the Directors’ Compensation Plan to make sure the overall program is still appropriate and reports its findings to the Board.
In 2020, the Governance Committee engaged Mercer (Canada) Limited for a formal review of directors’ compensation, including peer analysis and benchmarking to the peer group. Following this review, effective January 1,
2020, the Directors’ Compensation Plan was amended to increase: the Board retainer from US$260,000 to US$285,000, the Chair of the Board retainer (including the Board annual retainer) from US$520,000 to US$550,000, the Governance Committee chair retainer from US$10,000 to US$15,000 and the Corporate Social Responsibility Committee chair retainer from US$10,000 to US$15,000. All retainers are payable in U.S. dollars regardless of director residency.
Throughout the
COVID-19
pandemic, our priority has been to protect our employees, their families and our communities, while continuing to safely operate the critical infrastructure that delivers the energy people rely on every day. In the context of the
COVID-19
pandemic, reduced global energy demand and reduced commodity prices, the company initiated actions to bolster our resiliency. After a comprehensive review of operating expenditures, we initiated actions to reduce costs by approximately $300 million in 2020. These actions included company-wide compensation reductions, including a 15% reduction in Board compensation. Effective June 1, 2020, the Directors’ Compensation Plan was amended to reduce: the Board retainer from US$285,000 to US$242,250 and the Chair of the Board retainer (including the Board annual retainer) from US$550,000 to US$467,500. Board committee chair retainers were not amended.
To align with our director compensation philosophy of targeting director compensation at or about the 50th percentile in our peer group, the Directors’ Compensation Plan was amended effective April 1, 2021 to reinstate the Board and Chair of the Board retainers in effect immediately before the June 2020 reductions.
All
non-employee
director compensation in 2020 was paid under the Directors’ Compensation Plan. We do not compensate
non-employee
directors under our 2019 Long Term Incentive Plan.
2020 director share ownership requirements
Variable interest entities
Westcoast
About DSUs
A deferred share unit (“DSU”) is a notional share that has the same value as one Enbridge common share. Its value fluctuates with variations in the market price of Enbridge shares.
DSUs do not have voting rights but they accrue dividends as additional DSUs, at the same rate as dividends paid on our common shares.
Westcoast Energy Inc.

59
5

CONVENTIONS
We expect directorsThe terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to own Enbridge shares so they have an ongoing stake inInc. and its subsidiaries unless the companycontext suggests otherwise. These terms are used for convenience only and are alignednot 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 interests of shareholders. Directors must, within five years of becoming a director, hold at least three times their annual Board retainer in DSUs or Enbridge shares. The annual Board retainer since June 1, 2020 was US$242,250following: our corporate vision and strategy, including strategic priorities and enablers; the COVID-19 pandemic and the director share ownership requirement since June 1, 2020 was US$726,750. Effective April 1, 2021,duration and impact thereof; energy intensity and emissions reduction targets and related Environment, Social and Governance (ESG) matters; diversity and inclusion goals; expected supply of, demand for, and prices of crude oil, natural gas, natural gas liquids (NGLs), liquified natural gas and renewable energy; energy transition; anticipated utilization of our existing assets; expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected future cash flows and distributable cash flow; dividend growth and payout policy; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected strategic priorities and performance of the director share ownership requirement will increaseLiquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation and Energy Services businesses; expected costs related to US$855,000.
announced projects and projects under construction and for maintenance; expected in-service dates for announced projects and projects under construction and for maintenance; expected capital expenditures, investment capacity and capital allocation priorities; expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions and the timing thereof; expected benefits of transactions, including the realization of efficiencies, synergies and cost savings; expected future actions of regulators and courts; toll and rate cases discussions and filings, including Mainline System contracting; anticipated competition; United States Line 3 Replacement Program (US L3R Program), including anticipated in-service dates and capital costs; and Line 5 dual pipelines and related litigation and other matters.

If a decrease in the market value of Enbridge shares results in a director no longer meeting the share ownership requirements,Although we expect him or her to buy additional Enbridge shares in order to satisfy the minimum threshold.
DSUsbelieve these forward-looking statements are paid out when a director retires from the Board. They are settled in cash,reasonable based on the weighted averageinformation 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 tradingfollowing: the COVID-19 pandemic and the duration and impact thereof; the expected supply of and demand for crude oil, natural gas, NGL and renewable energy; prices of crude oil, natural gas, NGLs and renewable energy; anticipated utilization of assets; exchange rates; inflation; interest rates; availability and price of common shareslabor and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the timing and closing of acquisitions and dispositions; the realization of anticipated benefits and synergies of transactions; governmental legislation; litigation; estimated future dividends and impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; hedging program; expected EBITDA; expected earnings/(loss); expected future cash flows; and expected distributable cash flow. Assumptions regarding the TSXexpected supply of and demand for crude oil, natural gas, NGLs and renewable energy, and the last five trading daysprices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation, interest rates and the COVID-19 pandemic impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-
6


looking statement cannot be determined with certainty, particularly with respect to expected EBITDA, expected earnings/(loss), expected future cash flows, expected distributable cash flow or estimated future dividends. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather, customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes; and the COVID-19 pandemic and the duration and impact thereof.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities, operating performance, legislative and regulatory parameters; litigation, including with respect to the Dakota Access Pipeline (DAPL) and the Line 5 dual pipelines; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; our dividend policy; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; public opinion; changes in tax laws and tax rates; exchange rates; interest rates; commodity prices; political decisions; the supply of, demand for and prices of commodities; and the COVID-19 pandemic, including but not limited to those risks and uncertainties discussed in this Annual Report on Form 10-K and in our other filings with Canadian and US securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statement made in this Annual Report on Form 10-K or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

NON-GAAP AND OTHER FINANCIAL MEASURES
Part II.Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this Annual Report on Form 10-K makes reference to non-GAAP and other financial measures, including EBITDA. EBITDA is defined as earnings before the date that is three trading days before the payment date, multiplied by the number of DSUs the director holds. Directors may not engage in equity monetization transactions or hedges involving securitiesinterest, income taxes, depreciation and amortization. Management uses EBITDA to assess performance of Enbridge (see “Anti-hedging policy” on page 42).
2020 compensation components
Our Directors’ Compensation Plan has four components:
an annual retainer;
an annual retainer if he or she serves as the Chair of the Board or chair of a Board committee;
a travel fee for attending Board and Board committee meetings; and
reimbursement for reasonable travel and other
out-of-pocket
expenses relating to his or her duties as a director.
We do not have meeting attendance fees.
Our Directors’ Compensation Plan has been in effect since 2004 and was revised in 2010, 2013, 2015, 2016, 2018, 2019, 2020 and 2021. The table below shows the fee schedule for directors in 2020. Directors are paid quarterly. Mr. Monaco does not receive any director compensation because he is our President & CEO and is compensated in that role.
We have not granted stock options to directors since 2002. Mr. Ebel held certain Spectra Energy equity awards at the closing of the Merger Transaction that were generally treated in the same manner as those held by other employees of Spectra Energy.
Directors can receive their retainer in a combination of cash, Enbridge shares and DSUs, but they must receive a minimum amount in DSUs, described below. Travel fees are always paid in cash.
2020 Directors’ Compensation Plan retainers
1
 
    
Annual amount
(US$)
       
Cash
   
Enbridge
shares
   
DSUs
       
Cash
   
Enbridge
shares
   
DSUs
 
  Compensation component
   
Before minimum share
ownership
       
After minimum share
ownership
 
  Board retainer
  
 

285,000

(until May 31
242,250
(from June 1
 

 
           
       
  Additional retainers
              
Chair of the Board retainer
  
 

265,000

(until May 31
225,250
(from June 1
 

 
            
Board committee chair retainer
     Up to 50%    Up to 50%    
50%
to 100%
 
 
   Up to 65%    Up to 65%    
35%
to 100%
 
 
•  Audit, Finance & Risk
   25,000             
•  Human Resources & Compensation
   20,000             
•  Safety & Reliability
   15,000             
•  Corporate Social Responsibility
   15,000             
•  Governance
   15,000                               
  Travel Fee
(per meeting)
   1,500        100%    -    -        100%    -    - 
1
Effective April 1, 2021, the Directors’ Compensation Plan was amended to reinstate the Board and Chair of the Board retainers in effect immediately before the June 2020 reductions.
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For purposes of the explanation that follows in this paragraph, all references to “retainer” shall include the “Board retainer” and “additional retainers” described in the table above. Before a director reaches the minimum share ownership level, at least one half of their retainer will be paid in the form of DSUs, with the balance paid in cash, Enbridge shares or DSUs, according to a percentage mix they choose. Once a director reaches the minimum share ownership level, they can choose to receive between 35% and their entire retainer in DSUs, with the balance in cash, Enbridge shares or a combination of both, according to a percentage mix they choose. Directors are allocated the DSUs and Enbridge shares based on the weighted average of the trading price of the Enbridge shares on the TSX for the five trading days immediately preceding the date that is two weeks prior to the date of payment.
Directors who do not make a timely election as to the form in which they wish to receive their retainer will receive the applicable minimum amount in DSUs (in 2020, 35% if they have met the share ownership requirement and 50% if they have not) and the balance in cash.
The table below shows the compensation components in which each director’s annual retainer for the year ended December 31, 2020 was delivered.
Director
  
Cash (%)
  
Enbridge shares (%)
  
DSUs (%)
Pamela L. Carter
  40  25    35
Marcel R. Coutu
    -    -   100
Susan M. Cunningham
  30  20    50
Gregory L. Ebel
  50    -    50
J. Herb England
    -  65    35
Gregory J. Goff
  50    -    50
V. Maureen Kempston Darkes
    -    -   100
Teresa S. Madden
  50    -    50
Al Monaco
1
    -    -     -
Stephen S. Poloz
  30    -    70
Dan C. Tutcher
    -    -   100
Former Directors
         
Charles W. Fischer
2
  50    -    50
Catherine L. Williams
3
  20  40    40
1
Mr. Monaco does not receive any compensation as a director of Enbridge because he is our President & CEO.
2
Mr. Fischer passed away on June 17, 2020.
3
Ms. Williams retired from the Board effective May 5, 2020.
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Director compensation table
The table below provides information concerning the compensation of each
non-employee
director who served at any time in 2020. Mr. Monaco does not receive any compensation as a director of Enbridge because he is our President & CEO. For information on Mr. Monaco’s compensation, see page 45.
     
Share based awards
2
  
All other
compensation
  
Total
 
  
Fees
earned
1

(cash)
  
Enbridge
Shares
3
  
DSUs
3
  
Other
fees
4
  
Dividends
on DSUs
5
    
  Director
 
($)
  
(#)
  
($)
  
(#)
  
($)
  
($)
  
(#)
  
($)
  
($)
 
  Pamela L. Carter
  147,200   2,080   92,000   2,915   128,800   2,073   78   3,279   373,353 
  Marcel R. Coutu
  -   -   -   7,872   347,987   -   211   8,881   356,868 
  Susan M. Cunningham
  108,261   1,634   72,174   4,090   180,435   2,073   108   4,536   367,479 
  Gregory L. Ebel
  335,777   -   -   7,596   335,777   20,793   204   8,569   700,916 
  J. Herb England
  -   5,274   233,916   2,841   125,955   2,073   78   3,281   365,226 
  Gregory J. Goff
  151,270   -   -   3,486   151,270   2,073   82   3,428   308,041 
  V. Maureen Kempston Darkes
  -   -   -   8,430   372,295   2,073   225   9,433   383,801 
  Teresa S. Madden
  184,729   -   -   4,193   184,729   2,073   110   4,600   376,131 
  Al Monaco
6
  -   -   -   -   -   -   -   -   - 
  Stephen S. Poloz
  75,521   -   -   2,602   106,723   -   22   911   183,155 
  Dan C. Tutcher
  -   -   -   8,083   356,614   -   213   8,947   365,561 
  Former Directors
                                    
  Charles W. Fischer
7
  100,259   -   -   2,124   100,259   -   17   757   201,275 
  Catherine L. Williams
8
  38,605   1,181   57,155   1,182   57,155   -   13   575   153,491 
1
The cash portion of the retainers paid to the directors. Directors are paid quarterly in US$. The values presented in this table are in C$ and reflect U.S./Canadian exchange rates from the Bank of Canada of 1.3820 as at March 12, 2020, 1.3508 as at June 4, 2020, 1.3162 as at September 10, 2020, and 1.2880 as at December 3, 2020.
2
The portion of the retainer received as DSUs and Enbridge shares.
3
We pay directors quarterly. The value of the Enbridge shares and DSUs is based on the weighted average of the trading price of Enbridge shares on the TSX for the five trading days prior to the date that is two weeks prior to the applicable payment date. The weighted average Enbridge share prices were $50.52, $44.11, $42.21 and $39.93 for the first, second, third and fourth quarters, respectively, of 2020.
4
For all of our
non-employee
directors, includes a per meeting US$1,500 travel fee. For Mr. Ebel, these amounts also include expenses incurred for tax return preparation services.
5
Includes dividend equivalents granted in 2020 on DSUs granted in 2020 based on the 2020 quarterly dividend rate of $0.81. Dividend equivalents vest at the time of grant.
6
Mr. Monaco does not receive any compensation as a director of Enbridge because he is our President & CEO.
7
Mr. Fischer passed away on June 17, 2020.
8
Ms. Williams retired from the Board on May 5, 2020.
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Change in director equity ownership
The table below shows the change in each director nominee’s equity ownership from March 2, 2020 to March 2, 2021, the dates of the management information circular for the 2020 annual meeting of shareholders and of the Circular, respectively, and his or her status in meeting the share ownership requirements.
Director
  
Enbridge
shares (#)
   
Enbridge
stock options
(#)
   
DSUs(#)
   
Total
Enbridge shares +
DSUs (#)
   
Market (at risk) value
of equity holdings
(C$)
1,2
 
Pamela L. Carter
          
2021
   44,639    -    11,744    56,383    2,494,943 
2020
   42,559    -    8,056    50,615    2,576,810 
Change
   2,080    -    3,688    5,768    (81,867
Marcel R. Coutu
          
2021
   46,900    -    39,090    85,990    3,805,069 
2020
   29,400    -    28,595    57,995    2,952,525 
Change
   17,500    -    10,495    27,995    852,544 
Susan M. Cunningham
          
2021
   2,581    -    7,827    10,408    460,564 
2020
   947    -    3,281    4,228    215,247 
Change
   1,634    -    4,546    6,180    245,317 
Gregory L. Ebel
3
          
2021
   651,845    405,408    32,217    684,062    30,269,732 
2020
   651,845    405,408    22,489    674,334    34,330,344 
Change
   -    -    9,728    9,728    (4,060,612
J. Herb England
          
2021
   37,306    -    86,576    123,882    5,481,792 
2020
   32,032    -    77,530    109,562    5,577,801 
Change
   5,274    -    9,046    14,320    (96,010
Gregory J. Goff
          
2021
   -    -    3,644    3,644    161,230 
2020
   -    -    -    -    - 
Change
   -    -    3,644    3,644    161,230 
V. Maureen Kempston Darkes
          
2021
   21,735    -    57,789    79,524    3,518,945 
2020
   21,735    -    45,396    67,131    3,417,639 
Change
   -    -    12,393    12,393    101,306 
Teresa S. Madden
          
2021
   1,000    -    7,934    8,934    395,338 
2020
   -    -    3,281    3,281    167,036 
Change
   1,000    -    4,653    5,653    228,303 
Al Monaco
4
          
2021
   920,699    4,465,600    -    920,699    40,740,931 
2020
   876,512    3,987,520    -    876,512    44,623,226 
Change
   44,187    478,080    -    44,187    (3,882,295
Stephen S. Poloz
          
2021
   -    -    2,676    2,676    118,398 
2020
   -    -    -    -    - 
Change
   -    -    2,676    2,676    118,398 
Dan C. Tutcher
          
2021
   637,523    -    138,662    776,185    34,346,186 
2020
   637,523    -    120,743    758,266    38,603,322 
Change
   -    -    17,919    17,919    (4,257,136
Total
          
2021
   2,364,228    4,871,008    388,159    2,752,387    121,793,128 
2020
   2,292,553    4,392,928    309,371    2,601,924    132,463,951 
Change
   71,675    478,080    78,788    150,463    (10,670,823
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1
Based on the total market value of the Enbridge shares and/or DSUs owned by the director, based on the closing prices of $44.25 on the TSX on March 2, 2021 and $50.91 on March 2, 2020. These amounts have been rounded to the nearest dollar in Canadian dollars. Excludes stock options.
2
Directors must hold at least three times the annual Board retainer in DSUs or Enbridge shares within five years of becoming a director on our Board. All director nominees currently meet or exceed this requirement other than Mses. Madden and Cunningham, who have until February 12, 2024 and February 13, 2024, respectively, Mr. Goff, who has until February 11, 2025, and Mr. Poloz, who has until June 4, 2025.
3
Mr. Ebel’s stock options were Spectra Energy options that converted into options to purchase Enbridge shares upon the closing of the Merger Transaction. No new Enbridge stock options were granted to Mr. Ebel in his capacity as a Director of Enbridge or Chair of the Enbridge Board.
4
Mr. Monaco does not receive any compensation as a director of Enbridge. He is only compensated for his role as President & CEO. As President & CEO, he is subject to a share ownership requirement of six times base salary. Please see page 44 of this Amendment No. 1 on Form 10-K/A for information on his Enbridge share ownership as a multiple of his base salary.
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Non-GAAP
reconciliation
This Amendment No. 1 on Form 10-K/A contains references to DCF and DCF per common share, which are measures used for purposes of Enbridge’s executive compensation programs.set targets. Management believes the presentation of DCFEBITDA gives useful information to investors and shareholders as they provideit provides increased transparency and insight into the performance of the company. OurEnbridge.

The non-GAAP
and other financial measures described above are not measures that have a standardized meaning prescribed by generally accepted accounting principles in the United States of America (U.S.(US GAAP) and are not U.S.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


PART I

ITEM 1. BUSINESS

We are a leading North American energy infrastructure company. We safely and reliably deliver the energy people need and want to fuel quality of life. Our core businesses include Liquids Pipelines, which transports approximately 30% of the crude oil produced in North America; Gas Transmission and Midstream, which transports approximately 20% of the natural gas consumed in the US; Gas Distribution and Storage, which serves approximately 75% of Ontario residents via approximately 3.8 million meter connections; and Renewable Power Generation, which generates approximately 1,766 megawatts (MW) of net renewable power in North America and Europe. Our common shares trade on the Toronto Stock Exchange (TSX) and New York Stock Exchange (NYSE) under the symbol ENB. We were incorporated on April 13, 1970 under the Companies Ordinance of the Northwest Territories and were continued under the Canada Business Corporations Act on December 15, 1987.

A more detailed description of each of our businesses and underlying assets is provided below under Business Segments.

CORPORATE VISION AND STRATEGY

VISION
Our primary purpose as a company is to fuel quality of life by providing the energy people need and want, in a safe, clean and socially responsible way. Our vision to be the leading energy infrastructure company in North America supports this purpose. In pursuing this vision, we play a critical role in enabling the economic and social well-being of people in the areas we serve who depend on access to affordable and reliable energy of all types. Our infrastructure franchises transport, distribute, and generate energy including liquids, natural gas, renewable power, and low-carbon fuels like Renewable Natural Gas (RNG). We recognize that the energy system is changing, and we aim to bridge to that cleaner energy future by investing in low-carbon platforms while ensuring the continuity and stability that the world requires through the transition.

Our investor value proposition is founded on our ability to deliver predictable cash flows and a growing stream of dividends year-over-year through investment in, and efficient operation of, energy infrastructure assets that are strategically positioned between key supply basins and strong demand-pull markets. Our assets are underpinned by long-term contracts, regulated cost-of-service tolling frameworks, power purchase agreements, and other low-risk commercial arrangements.

We strive to be a leader in ESG; worker and public safety; emissions reduction; stakeholder relations; customer service; community investment; and employee engagement and satisfaction.

STRATEGY
An in-depth understanding of energy supply and demand fundamentals coupled with disciplined capital allocation principles has helped us become an industry leader supported by a diverse set of assets across the energy system. Our assets have reliably generated low-risk, resilient cash flows through many commodity and economic cycles, including the COVID-19 pandemic and the ensuing volatile economic recovery.

8


To ensure we continue to be an industry leader and value creator going forward, we maintain a robust strategic planning approach. We regularly conduct scenario and resiliency analysis on both our assets and on our business strategy. We test various value enhancement and maximization options, and we engage regularly with our Board of Directors (Board) to ensure alignment and maintain active oversight. This Board participation includes updates and discussions throughout the year and a dedicated session to Strategy Planning annually. This comprehensive approach will continue to guide investment decisions moving forward.

Predictable growth is a hallmark of our investor value proposition. We see a 5-7% compound annual growth rate in distributable cash flow per share through 2024, relative to 2021, underpinned by opportunities to advance returns in our base business and grow organically through disciplined capital allocation. Our diversified footprint allows for selective investment in both our core businesses and in emerging low carbon energy platforms such as carbon capture and storage (CCS), hydrogen gas (H2), and RNG.

In 2021, we progressed several of our strategic priorities. For example:

Our Liquids Pipelines team delivered record mainline throughput, placed $5.6 billion of capital into service (Line 3 Replacement, Southern Access), added 90 kbpd of system expansions into Petroleum Administration for Defense Districts (PADD) III, and acquired the Ingleside Energy Center in Corpus Christi and related assets which extends our reach into global light-oil export markets.

Our Gas Transmission and Midstream business successfully placed $3.1 billion of capital into service, completed favorable rate settlements, which added $150 million of incremental EBITDA, and continued to advance more than $2 billion of expansion opportunities.

Our Gas Distribution and Storage utility provided uninterrupted services during the ongoing pandemic, added over 40 thousand new customers, completed 190 modernization projects, placed two RNG projects into service, and completed an H2 blending pilot.

In Europe, Renewable Power Generation advanced construction of the 480 MW Saint Nazaire project, the 500 MW Fécamp project, and the 448 MW Calvados project, and sanctioned the Provence Grand Large floating offshore wind facility.

We advanced our self-power strategy and commissioned two projects, Alberta Solar One on our Liquids Pipeline system and Heidlersberg on our Gas Transmission system. Ten additional self-power facilities (~100MW) were approved for future development.

We established our New Energy Technologies team to advance our low-carbon strategy. Through several strategic partnerships, we are working to develop solutions in RNG, H2 and CCS and to accelerate global and industry-specific low-carbon objectives.

We continued to make meaningful progress towards our ESG goals that include a 35% reduction in greenhouse gas (GHG) emissions intensity from our operations by 2030 (net zero GHG emissions by 2050) and increased representation of diverse groups within our workforce and the Board of Directors by 2025.

We sold $1.2 billion of assets at attractive valuations, further strengthening our financial flexibility. In addition, we continued to reduce our operating costs ($1.2 billion since 2017), increasing our profitability and competitiveness.

9


These achievements are discussed in further detail in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Looking ahead, our near-term strategic priorities remain similar to years past. As always, proactively advancing the safety of communities and assets, protecting the environment, and maintaining reliability will always be our top priorities. We are focused on enhancing the value of our existing assets in Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, and Renewable Power Generation.

We will continue to enhance base business returns, capitalize on our advantaged liquids and natural gas pipeline infrastructure, emphasizing export-driven opportunities and in-franchise organic growth, and developing low-carbon opportunities across our business.

Our key strategic priorities are summarized below:

Ensure Safe Reliable Operations
Safety and operational reliability remain the foundation of our strategy. Our commitment to safety and operational reliability means achieving and maintaining industry leadership in safety (process, public and personal) and ensuring the reliability and integrity of the systems we operate, in order to generate, transport and deliver energy while protecting people and the environment.

Enhance Returns from our Base Businesses
A key priority is to drive growth through an ongoing focus on optimization, productivity, and efficiency across all our businesses. Examples include: the application of drag-reducing agents and pump station horsepower additions to optimize throughput on our liquids system, the execution of toll settlements and rate case filings to optimize revenue within our gas transmission franchises, the expansion of low-carbon gas offerings to modernize and integrate value chains at our gas utility, and more generally, and the creation of sustainable cost savings across the organization through process improvement and/or system enhancements.

Execute the Capital Program and Grow Core Business
Successful project execution is integral to our financial performance and to the strategic positioning of our business over the long term. Our ongoing objective is to deliver our slate of secured projects (currently $9 billion through 2024) at the lowest practical cost while maintaining the highest standards for safety, quality, customer satisfaction and environmental and regulatory compliance. For a discussion of our current portfolio of capital projects, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

In seeking to extend growth, we expect to have sufficient self-funding capacity of about $5 to $6 billion per year to invest in new organic growth capital without issuing any additional common equity and maintaining key credit metrics. We will remain disciplined and deploy capital towards the best uses, prioritizing balance sheet strength, investment in low capital intensity growth and regulated utility or utility-like projects. We will carefully assess our remaining investable capacity, deploying capital to the most value-enhancing opportunities available to us, including further organic growth, asset acquisitions, and share buybacks, or further deleveraging our balance sheet.

Looking ahead, we see strong utilization of our existing network and opportunities for future growth within each of our businesses. For example:

Our liquids pipelines infrastructure will remain a vital connection between key supply basins and demand-pull markets such as the refinery hubs in the US Midwest, Eastern Canada, and the US Gulf Coast. The table belowemergence of CCS offers the potential to provide new growth opportunities over the long term.

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Our natural gas pipelines business will seek extension and expansion opportunities driven by new load demand from gas-fired power generation, industrial growth, and coastal liquefied natural gas (LNG) plants. Looking forward, blending RNG and H2 production projects into our system will enhance asset longevity and enable us to offer a differentiated low-carbon service to customers.

Our gas distribution utility will continue to grow through customer additions, productivity enhancements, modernization investments and facilities that blend H2 and RNG into gas supply, and expansion of our demand-side management and distributed energy programs.

Our mature capabilities in the offshore and onshore wind sector position us well to compete for new projects across the development cycle in Europe and North America, while our multi-year program to self-power existing pipeline compressor stations represents highly visible and scalable growth.

Maintain Financial Strength and Flexibility
The maintenance of our financial strength is critical to our strategy. Our financing strategies are designed to retain strong investment-grade credit ratings to ensure that we have the financial capacity to meet our capital funding needs and the flexibility to manage capital market disruptions. Our current secured capital program, which extends to 2024, can be readily financed through internally generated cash flow and available balance sheet capacity without issuance of additional common equity and we will seek to secure new growth within our “self-funded” equity model. In addition, we continue to look at opportunities to monetize non-core assets at attractive valuations. For further discussion on our financing strategies, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.

Disciplined Capital Allocation
We assess the latest fundamental trends, monitor the business landscape and proactively conduct business development activities with the goal of identifying an industry-leading opportunity set for capital deployment. Opportunities are screened, analyzed and assessed using a disciplined investment framework with the objective of ensuring effective deployment of capital to achieve attractive risk-adjusted returns, while maintaining our low-risk “utility-like” business model.

All investment opportunities are evaluated based on their potential to advance our strategy, mitigate risk, support our ESG goals, and create additional financial flexibility. Our primary emphasis in the near term is on low capital-intensive opportunities to enhance returns in existing businesses (organic expansions and optimizations), modernization of our systems and utility rate-based investments. Execution risk remains high for large scale, long-duration development projects and, therefore, our focus will be on projects where we can carefully manage at-risk capital during the permitting and construction phases.

In evaluating typical investment opportunities, we also consider other potential capital allocation alternatives. Other alternatives for capital deployment depend on our current outlook and include further dividend increases, further debt reduction, and/or share re-purchases.

Adapt to Energy Transition Over Time
As the global population grows and standards of living continue to improve around the world, more energy will be needed. At the same time, our society increasingly recognizes the impacts of greenhouse gas emissions on the world’s climate. Accordingly, energy systems are being reshaped as industry participants, regulators and consumers seek to lower emissions. As a diversified energy infrastructure company, we are well positioned to play a key role in the transition to a low-emissions economy by leading the development of the future energy systems and partnering with customers on their low-carbon strategies, while at the same time working to reduce our own emissions. Furthermore, we have tested our assets for various energy transition scenarios and concluded that they are highly resilient and can be relied upon for stable cash flow generation well into the future.

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We believe that diversification and innovation will play a significant role in the transition to a low-carbon future. To date, we have made large investments in natural gas infrastructure and continue to see significant opportunity in renewable energy. Our focus areas in renewable energy remain in offshore wind and utility-scale onshore projects. We are also taking a leadership role in other low-carbon platforms like CCS, H2 and RNG where we can leverage our infrastructure capability and stakeholder relationships to accelerate growth and extend the value of our existing assets. Additionally, all new investments that we make will need to have a clear path to achieve net zero emissions.

We recognize our customer's expectations of a transition to a lower-carbon economy and are working actively to be a differentiated service provider by leveraging our ESG leadership and world-class execution capabilities.

STRATEGIC ENABLERS
Our success in executing on our strategic priorities is enabled by our commitment to ESG, the quality and capabilities of our people, and the extent to which we embrace technology and innovation as a competitive advantage.

ESG
Sustainability is integral to our ability to safely and reliably deliver the energy people need and want. How well we perform as a steward of our environment; as a safe operator of essential energy infrastructure; as a diverse and inclusive employer; and as a responsible corporate citizen is inextricably linked to our ability to achieve our strategic priorities and create long-term value for all stakeholders.

Our commitment to strong ESG practices and performance has long been core to how we do business and we are proud to be recognized as a leader amongst our peers. In 2020, we set out ambitious goals1 including:

Net zero GHG emissions by 2050 with an interim target to reduce GHG emissions intensity 35% by 2030 compared to the 2018 baseline.

Increased representation of diverse groups within our workforce by 2025, including representation goals of 40% women and 28% racial and ethnic groups, along with new initiatives to enhance supplier diversity.

Strengthening diversity on our Board with representation goals of 40% women and 20% racial and ethnic groups by 2025.

Annual safety and reliability targets that drive continuous improvement towards our goal of zero incidents, injuries, and implementation of robust cyber defense programs.

Beginning in 2021, we began linking ESG performance to incentive compensation and are making meaningful progress toward these targets by executing on specific action plans. In addition, we issued our first sustainability-linked loan and sustainability-linked bond that ties our financing to our ESG goals.

1 All percentages or specific goals regarding inclusion, diversity, equity and accessibility are aspirational goals which we intend to achieve in a manner compliant with state, local, provincial and federal law, including, but not limited to, US federal regulations, Equal Employment Opportunity Commission, Department of Labor and Office of Federal Contract Compliance Programs.
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Enbridge aims to continuously strengthen its approach to emissions reporting and reduction and is expanding its approach to include the following additional actions:

Ensure that investment decision making aligns with Enbridge’s interim and long-term emissions reduction goals.

Continue to proactively work with the organizations developing science-based guidelines for emissions targets in the midstream sector.

Work with key suppliers to support the further reduction of Scope 3 emissions.

Further develop low carbon energy partnerships to drive innovation across our business, with a focus on renewable power, renewable natural gas, hydrogen and carbon capture.

Achieving our goals will put us in a better position to successfully transition to a low-carbon, more diverse, and inclusive future.

People
Our employees are essential to our long-term success and enhancing the capability of our people to maximize their potential is a key area of focus. We value diversity, and diverse thought, and have embedded inclusive practices in our programs and approach to people management. Furthermore, we strive to maintain industry competitive compensation, flexibility, and retention programs that provide both short-term and long-term performance incentives.

Technology
Given the competitive climate of today’s energy sector, we recognize the vital role technology can play in helping to achieve our strategic objectives. We’re committed to pursuing innovation and technology solutions that further improve our safety performance, maximize revenues, improve efficiencies, and enable transition to new, cleaner energy solutions. Our two Technology and Innovation labs, located in Calgary and Houston, embody our commitment to technology enabled business solutions. Leveraging the benefits of technology to contribute to safety, reliability and the profitability of assets has become entrenched in our everyday operations.

We provide annual progress updates related to the above initiatives, along with our assumptions and other relevant information, in our annual Sustainability Report which can be found at https://www.enbridge.com/sustainability-reports. Unless otherwise specifically stated, none of the information contained on, or connected to, the Enbridge website, including our annual Sustainability Report, is incorporated by reference in, or otherwise part of, this Annual Report on Form 10-K.

BUSINESS SEGMENTS

Our activities are carried out through five business segments: Liquids Pipelines; Gas Transmission and Midstream; Gas Distribution and Storage; Renewable Power Generation; and Energy Services, as discussed below.

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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. We have operated, and frequently expanded, the Canadian Mainline since 1949. The Lakehead System is the portion of the Mainline System in the US. It is an interstate common carrier pipeline system regulated by the Federal Energy Regulatory Commission (FERC) and is the primary transporter of crude oil and liquid petroleum from western Canada to the US.

Tolling Framework
The Competitive Toll Settlement (CTS) which governed tolls paid for products shipped on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis, expired on June 30, 2021. The CTS was a 10-year negotiated agreement and provided for a Canadian Local Toll (CLT) for deliveries within western Canada, as well as an International Joint Tariff (IJT) for crude oil shipments originating in western Canada, on the Canadian Mainline, and delivered into the US, via the Lakehead System, and into eastern Canada. The IJT tolls were denominated in US dollars.

On December 19, 2019, we submitted an application to the Canada Energy Regulator (CER) to implement contracting on our Canadian Mainline System. On November 26, 2021, the CER denied the application on the basis that, among other things, contracting as proposed would result in a significant change to access the Canadian Mainline and potentially inequitable outcomes to some shippers and non-shippers without a compelling justification.

Effective July 1, 2021, the Mainline System is on Interim Tolls which will remain in effect until new tolls are approved by the CER. In accordance with the terms of the CTS, Interim Tolls are equal to the CTS exit tolls on June 30, 2021 and are subject to finalization and adjustment applicable to the interim period, if any. We are currently exploring, with customers and other stakeholders, alternatives that may include: a modified and extended CTS, a new incentive rate-making agreement, or a cost-of-service rate-making structure. Any negotiated settlement would require CER approval before implementation. New tolling framework clarity is expected by 2023.

Shippers continue to nominate volumes on a monthly basis and we continue to allocate capacity to maximize the efficiency of the Mainline System.

Local tolls for service on the Lakehead System are not affected by Interim Tolls and continue to be established pursuant to the Lakehead System’s existing toll agreements, as described below.Under Interim Tolls, the Canadian Mainline’s share of the toll relating to pipeline transportation of a batch from any western Canada receipt point to the US border is equal to the toll applicable to that batch’s US delivery point less the Lakehead System’s local toll to that delivery point. While on Interim Tolls, we will continue to refer to this amount as the Canadian Mainline IJT Residual Benchmark Toll which is denominated in US dollars.

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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 kbpd to Edmonton and 1,370 kbpd into Hardisty, with Norlite providing approximately 218 kbpd of diluent capacity into the Fort McMurray region. We have a 50% interest in the Woodland Pipeline and a 70% interest in Norlite. The Regional Oil Sands System is anchored by long-term agreements with multiple oil sands producers that provide cash flow stability and also include provisions for the recovery of some of the operating costs of this system.

GULF COAST AND MID-CONTINENT
Gulf Coast includes Seaway Crude Pipeline System (Seaway Pipeline), Flanagan South Pipeline (Flanagan South), Spearhead Pipeline, Gray Oak Pipeline and the Enbridge Ingleside Energy Center (EIEC), as well as the Mid-Continent System (Cushing Terminal).

We have a 50% interest in the 1,078-kilometer (670-mile) Seaway Pipeline, including the 805-kilometer (500-mile), 30-inch diameter long-haul system between Cushing, Oklahoma and Freeport, Texas, as well as the Texas City Terminal and Distribution System which serve refineries in the Houston and Texas City areas. Total aggregate capacity on the Seaway Pipeline system is approximately 950 kbpd. Seaway Pipeline also includes 8.8 million barrels of crude oil storage tank capacity on the Texas Gulf Coast.

Flanagan South is a 950-kilometer (590-mile), 36-inch diameter interstate crude oil pipeline that originates at our terminal at Flanagan, Illinois, a delivery point on the Lakehead System, and terminates in Cushing, Oklahoma. Flanagan South has a capacity of approximately 600 kbpd.

Spearhead Pipeline is a long-haul pipeline that delivers crude oil from Flanagan, Illinois, a delivery point on the Lakehead System, to Cushing, Oklahoma. The Spearhead pipeline has a capacity of approximately 193 kbpd.

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The Gray Oak pipeline is a 1,368-kilometer (850-mile) crude oil system, which runs from the Permian Basin in West Texas to the US Gulf Coast. The Gray Oak pipeline has an expected average annual capacity of 900 kbpd and transports light crude oil. We have an effective 22.8% interest in the pipeline. Initial in-service for the pipeline commenced in November 2019 with full service achieved in the second quarter of 2020.

The Mid-Continent System is comprised of storage terminals at Cushing, Oklahoma (Cushing Terminal), consisting of over 80 individual storage tanks ranging in size from 78 to 570 thousand barrels. Total storage shell capacity of Cushing Terminal is approximately 20 million barrels. A portion of the storage facilities are used for operational purposes, while the remainder are contracted to various crude oil market participants for their term storage requirements.Contract fees include fixed monthly storage fees, throughput fees for receiving and delivering crude to and from connecting pipelines and terminals, as well as blending fees.

In October 2021, we acquired a 100 percent operating interest in the Ingleside Energy Center (renamed the Enbridge Ingleside Energy Center (EIEC)), located near Corpus Christi, Texas. This terminal is comprised of 15.6 million barrels of storage and 1.5 million barrels per day of export capacity. We also acquired a 20% interest in the 670-kbpd Cactus II Pipeline, a 100% interest in the 300-kbpd Viola pipeline, and a 100% interest in the 350-thousand-barrel Taft Terminal.

OTHER
Other includes Southern Lights Pipeline, Express-Platte System, Bakken System and Feeder Pipelines and Other.

Southern Lights Pipeline is a single stream 180 kbpd 16/18/20-inch diameter pipeline that ships diluent from the Manhattan Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. Both the Canadian portion of Southern Lights Pipeline and the US portion of Southern Lights Pipeline receive tariff revenues under long-term contracts with committed shippers. Southern Lights Pipeline capacity is 90% contracted with the remaining 10% of the capacity assigned for shippers to ship uncommitted volumes.

The Express-Platte System consists of the Express pipeline and the Platte pipeline, and crude oil storage of approximately 5.6 million barrels. It is an approximate 2,736-kilometer (1,700-mile) long crude oil transportation system, which begins at Hardisty, Alberta, and terminates at Wood River, Illinois. The 310 kbpd Express pipeline carries crude oil to US refining markets in the Rocky Mountains area, including Montana, Wyoming, Colorado and Utah. The 145 to 164 kbpd Platte pipeline, which interconnects with the Express pipeline at Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the midwest. Express pipeline capacity is typically committed under long-term take-or-pay contracts with shippers. A small portion of Express pipeline capacity and all of the Platte pipeline capacity is used by uncommitted shippers who pay only for the pipeline capacity they actually use in a given month.

The Bakken System consists of the North Dakota System and the Bakken Pipeline System. The North Dakota System services the Bakken in North Dakota and is comprised of a crude oil gathering and interstate pipeline transportation system. The gathering system provides delivery to Clearbrook, Minnesota for service on the Lakehead system or a variety of interconnecting pipeline and rail export facilities. The interstate portion of the system has both US and Canadian components that extend from Berthold, North Dakota into Cromer, Manitoba.

Tariffs on the US portion of the North Dakota System are governed by the FERC. The Canadian portion is categorized as a Group 2 pipeline, and as such, its tolls are regulated by the CER on a complaint basis. Tolls on the interstate pipeline system are based on long-term take-or-pay agreements with anchor shippers.

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We have an effective 27.6% interest in the Bakken Pipeline System, which connects the Bakken formation in North Dakota to markets in eastern PADD II and the US Gulf Coast. The Bakken Pipeline System consists of the DAPL from the Bakken area in North Dakota to Patoka, Illinois, and the Energy Transfer Crude Oil Pipeline from Patoka, Illinois to Nederland, Texas. Current capacity is 750 kbpd of crude oil with the potential to be expanded through additional pumping horsepower. The Bakken Pipeline System is anchored by long-term throughput commitments from a number of producers.

Feeder Pipelines and Other includes a number of liquids storage assets and pipeline systems in Canada and the US.

Key assets included in Feeder Pipelines and Other are the Hardisty Contract Terminal and Hardisty Storage Caverns located near Hardisty, Alberta, a key crude oil pipeline hub in western Canada and the Southern Access Extension (SAX) pipeline which originates in Flanagan, Illinois and delivers to Patoka, Illinois. We have an effective 65% interest in the 300 kbpd SAX pipeline of which the majority of its capacity is commercially secured under long-term take-or-pay contracts with shippers.

Feeder Pipelines and Other also includes Patoka Storage, the Toledo pipelinesystem and the Norman Wells (NW) System. Patoka Storage is comprised of four storage tanks with 480 thousand barrels of shell capacity located in Patoka, Illinois. The 101 kbpd Toledo pipeline system connects with the Lakehead System and delivers to Ohio and Michigan. The 45 kbpd NW System transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta and has a cost-of-service rate structure based on established terms with shippers.

COMPETITION
Competition to our liquids pipelines network comes primarily from infrastructure or logistics alternatives that transport liquid hydrocarbons from production basins in, which we operate, to markets in Canada, the US and internationally. Competition from existing and proposed pipelines is based primarily on access to supply, end use markets, the cost of transportation, contract structure and the quality and reliability of service. Additionally, volatile crude price differentials and insufficient pipeline capacity on either our or competitors' pipelines can make transportation of crude oil by rail competitive, particularly to markets not currently served by pipelines.

We believe that our liquids pipelines systems will continue to provide competitive and attractive options to producers in the Western Canadian Sedimentary Basin (WCSB), North Dakota, and more recently the Permian Basin, due to our market access, competitive tolls and flexibility through our multiple delivery and storage points. We also employ long-term agreements with shippers, which mitigates competition risk by ensuring consistent supply to our liquids pipelines network. Our current complement of growth projects to expand market access and to enhance capacity on our pipeline system will provide additional competitive solutions for liquids transportation. We have a proven track record of successfully executing projects to meet the needs of our customers.

SUPPLY AND DEMAND
We have an established and successful history of being the largest transporter of crude oil to the US, the world’s largest market for crude oil. While US demand for Canadian crude oil production will support the use of our infrastructure for the foreseeable future, North American and global crude oil supply and demand fundamentals are shifting, and we have a role to play in this transition by developing long-term transportation options that enable the efficient flow of crude oil from supply regions to end-user markets, both domestic and global.

The COVID-19 pandemic had a significant negative impact on the crude oil market in 2020 with decreased demand from the economic slowdown and government imposed mobility restrictions. However, 2021 has seen global crude oil demand recover to levels close to pre-pandemic highs. International prices have strengthened to multi-year highs as global demand has outpaced the return of supply as publicly traded producers have adopted a more disciplined approach to capital allocation for new drilling.
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Our Mainline System throughput, as measured at the Canada/US border at Gretna, Manitoba ended the year delivering 3.1 million barrels per day, as the Line 3 Replacement program has come into service. Refinery demand in the upper Midwest PADD II market has been strong given the economic recovery and enhanced mobility demand. On the US Gulf Coast, lower supply of heavy crude from Latin America and the Middle East is driving increased demand for Canadian heavy crude.
Global crude oil demand in most base case forecasts is expected to grow into the next decade, primarily driven by emerging economies in regions outside the Organization for Economic Cooperation and Development (OECD), such as India and China. In North America, demand growth for transportation fuels is expected to moderate over time due to vehicle fuel efficiency improvement and increasing sales of electric vehicles.

New supply to meet this growing demand will primarily come from Organization of the Petroleum Exporting Countries (OPEC) countries and North America. Growth in supply from OPEC will be led by Saudi Arabia and the United Arab Emirates with their significant low cost reserves and could be supplemented by the return of sanctioned Iranian production. Growth in North America will be driven by the Permian Basin which is a large and cost competitive light crude oil resource base. In addition, heavy crude oil growth is expected from the WCSB as additional egress availability will support expansion of existing projects and some potential new greenfield facilities.

The combination of long term demand growth in non-OECD nations, domestic demand contraction over time, and continued production growth in the Permian Basin and WCSB highlights the importance of our strategic asset footprint and reinforces the need for additional export oriented infrastructure. We are well positioned to meet these evolving supply and demand fundamentals through expansion of system capacity for incremental access to the US Gulf Coast, and through further development of our new Enbridge Ingleside Energy Center in Corpus Christi, the largest crude oil export facility in North America.

Opposition to fossil fuel development in conjunction with evolving consumer preferences and new technology could underpin accelerated energy transition scenarios impacting long term supply and demand of crude oil. We continue to closely monitor the evolution of all of these factors to be able to pro-actively adapt our business to help meet our customers’ and society’s energy needs.

Progress on the development and construction of our commercially secured growth projects is discussed in Part II. Item 7.Management's Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

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GAS TRANSMISSION AND MIDSTREAM

Gas Transmission and Midstream consists of our investments in natural gas pipelines and gathering and processing facilities in Canada and the US, including US Gas Transmission, Canadian Gas Transmission, US Midstream and other assets.
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US GAS TRANSMISSION
US Gas Transmission includes ownership interests in Texas Eastern Transmission, L.P. (Texas Eastern), Algonquin Gas Transmission, LLC (Algonquin), Maritimes & Northeast (M&N) (US and Canada), East Tennessee Natural Gas, LLC (East Tennessee), Gulfstream Natural Gas System, L.L.C. (Gulfstream), Sabal Trail Transmission (Sabal Trail), NEXUS Gas Transmission Pipeline (NEXUS), Valley Crossing Pipeline, LLC. (Valley Crossing), Southeast Supply Header (SESH), Vector Pipeline L.P. (Vector) and certain other gas pipeline and storage assets. The US Gas Transmission business primarily provides transmission and storage of natural gas through interstate pipeline systems for customers in various regions of the northeastern, southern and midwestern US.

The Texas Eastern natural gas transmission system extends from supply and demand centers in the Gulf Coast region of Texas and Louisiana to supply and demand centers in Ohio, Pennsylvania, New Jersey and New York. Texas Eastern's onshore system has a peak day capacity of 13.09 billion cubic feet per day (bcf/d) of natural gas on approximately 13,807-kilometers (8,579-miles) of pipeline and associated compressor stations. Texas Eastern is also connected to four affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas Transmission business.

The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to M&N US. The system has a peak day capacity of 3.09 bcf/d of natural gas on approximately 1,820-kilometers (1,131-miles) of pipeline with associated compressor stations.

M&N US has a peak day capacity of 0.83 bcf/d of natural gas on approximately 552-kilometers (343-miles) of mainline interstate natural gas transmission system, including associated compressor stations, which extends from northeastern Massachusetts to the border of Canada near Baileyville, Maine. M&N Canada has a peak day capacity 0.55 bcf/d on approximately 885-kilometers (550-miles) of interprovincial natural gas transmission mainline system that extends from Goldboro, Nova Scotia to the US border near Baileyville, Maine. We have a 78% interest in M&N US and M&N Canada.

East Tennessee’s natural gas transmission system has a peak day capacity of 1.86 bcf/d of natural gas, crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems totaling approximately 2,456-kilometers (1,526-miles) of pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East Tennessee has a LNG storage facility in Tennessee and also connects to the Saltville storage facilities in Virginia.

Gulfstream is an approximately 1,199-kilometer (745-mile) interstate natural gas transmission system with associated compressor stations. Gulfstream has a peak day capacity of 1.31 bcf/d of natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and southern Florida. We have a 50% interest in Gulfstream.

Sabal Trail is an approximately 832-kilometer (517-mile) pipeline that provides firm natural gas transportation. Facilities include a pipeline, laterals and various compressor stations. The pipeline infrastructure is located in Alabama, Georgia and Florida, and adds approximately 1.0 bcf/d of capacity enabling the access of onshore gas supplies. We have a 50% interest in Sabal Trail.

NEXUS is an approximately 414-kilometer (257-mile) interstate natural gas transmission system with associated compressor stations. NEXUS transports natural gas from our Texas Eastern system in Ohio to our Vector interstate pipeline in Michigan, with peak day capacity of 1.4 bcf/d. Through its interconnect with Vector, NEXUS provides a reconciliationconnection to Dawn Hub, the largest integrated underground storage facility in Canada and one of the
non-GAAP
measures largest in North America, located in southwestern Ontario adjacent to comparable GAAP measures.the Greater Toronto Area. We have a 50% interest in NEXUS.

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Valley Crossing is an approximately 285-kilometer (177-mile) intrastate natural gas transmission system, with associated compressor stations. The pipeline infrastructure is located in Texas and provides market access of up to 2.6 bcf/d of design capacity to the Comisión Federal de Electricidad, Mexico’s state-owned utility.

SESH is an approximately 462-kilometer (287-mile) natural gas transmission system with associated compressor stations. SESH extends from the Perryville Hub in northeastern Louisiana where the shale gas production of eastern Texas, northern Louisiana and Arkansas, along with conventional production, is reached from six major interconnections. SESH extends to Alabama, interconnecting with 14 major north-south pipelines and three high-deliverability storage facilities and has a peak day capacity of 1.1 bcf/d of natural gas. We have a 50% interest in SESH.

Vector is an approximately 560-kilometer (348-mile) pipeline travelling between Joliet, Illinois in the Chicago area and Ontario. Vector can deliver 1.745 bcf/d of natural gas, of which 455 million cubic feet per day (mmcf/d) is leased to NEXUS. We have a 60% interest in Vector.

Transmission and storage services are generally provided under firm agreements where customers reserve capacity in pipelines and storage facilities. The vast majority of these agreements provide for fixed reservation charges that are paid monthly regardless of the actual volumes transported on the pipelines, plus a small variable component that is based on volumes transported, injected or withdrawn, which is intended to recover variable costs.

Interruptible transmission and storage services are also available where customers can use capacity if it exists at the time of the request and are generally at a higher toll than long-term contracted rates. Interruptible revenues depend on the amount of volumes transported or stored and the associated rates for this service. Storage operations also provide a variety of other value-added services including natural gas parking, loaning and balancing services to meet customers’ needs.

CANADIAN GAS TRANSMISSION
Canadian Gas Transmission is comprised of Westcoast Energy Inc.’s (Westcoast) British Columbia (BC) Pipeline, Alliance Pipeline and other minor midstream gas gathering pipelines.

BC Pipeline has a peak day capacity of 3.6 bcf/d of natural gas on approximately 2,950-kilometers (1,833-miles) of transmission pipeline in BC and Alberta that includes associated mainline compressor stations. It provides cost-of-service based natural gas transmission services.

Alliance Pipeline is an approximately 3,000-kilometer (1,864-mile) integrated, high-pressure natural gas transmission pipeline with approximately 860-kilometers (534-miles) of lateral pipelines and related infrastructure. It transports liquids-rich natural gas from northeast BC, northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub downstream of the Aux Sable NGL extraction and fractionation plant at Channahon, Illinois. The system has a peak day capacity of 1.8 bcf/d of natural gas. We have a 50% interest in Alliance Pipeline.

The majority of transportation services provided by Canadian Gas Transmission are under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline, plus a small variable component that is based on volumes transported to recover variable costs. Canadian Gas Transmission also provides interruptible transmission services where customers can use capacity if it is available at the time of request. Payments under these services are based on volumes transported.

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US MIDSTREAM
US Midstream includes a 42.7% interest in each of Aux Sable Liquid Products LP and Aux Sable Midstream LLC, and a 50% interest in Aux Sable Canada LP (collectively, Aux Sable). Aux Sable Liquid Products LP owns and operates an NGL extraction and fractionation plant at Channahon, Illinois, outside Chicago, near the terminus of Alliance Pipeline. Aux Sable also owns facilities connected to Alliance Pipeline that facilitatedelivery of liquids-rich natural gas for processing at the Aux Sable plant. These facilities include the Palermo Conditioning Plant and the Prairie Rose Pipeline in the Bakken area of North Dakota, owned and operated by Aux Sable Midstream US; and Aux Sable Canada’s interests in the Montney area of BC, comprising the Septimus Pipeline. Aux Sable Canada also owns a facility which processes refinery/upgrader offgas in Fort Saskatchewan, Alberta.

US Midstream also includes a 50% investment in DCP Midstream, LLC (DCP Midstream), which indirectly owns approximately 57% of DCP Midstream, LP, including limited partner and general partner interests. DCP Midstream, LP is a master limited partnership, with a diversified portfolio of assets, engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGLs; and recovering and selling condensate. DCP Midstream, LP owns and operates more than 36 plants and approximately 90,123-kilometers (56,000-miles) of natural gas and natural gas liquids pipelines, with operations in nine states across major producing regions.

OTHER
Other consists primarily of our offshore assets. Enbridge Offshore Pipelines is comprised of 11 natural gas gathering and FERC regulated transmission pipelines and four oil pipelines. These pipelines are located in four major corridors in the Gulf of Mexico, extending to deepwater developments, and include almost 2,100-kilometers (1,300-miles) of underwater pipe and onshore facilities with total capacity of approximately 6.5 bcf/d.

COMPETITION
Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service.

The natural gas transported in our business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, nuclear and renewable energy. Factors that influence the demand for natural gas include price changes, the availability of natural gas and other forms of energy, levels of business activity, long-term economic conditions, conservation, legislation, governmental regulations, the ability to convert to alternative fuels, weather and other factors.

Competition exists in all markets that our businesses serve. Competitors include interstate/interprovincial and intrastate/intraprovincial pipelines or their affiliates and other midstream businesses that transport, gather, treat, process and market natural gas or NGLs. Because pipelines are generally the most efficient mode of transportation for natural gas over land, the most significant competitors of our natural gas pipelines are other pipeline companies.

SUPPLY AND DEMAND
Our gas transmission assets make up one of the largest natural gas transportation networks in North America, driving connectivity between prolific supply basins and major demand centers within the continent. Our systems have been integral to the transition in supply and demand markets over the last decade and will continue to play a part as the energy landscape evolves.

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In 2010, natural gas production in each of the Appalachian and Permian basins were less than 5.0 bcf/d each. Today, these regions produce more than 47.5 bcf/d of natural gas on a combined basis. Improved technology and increased shale gas drilling have increased the supply of low-cost natural gas. As well, there has been and continues to be a corresponding increase in demand for our natural gas infrastructure in North America. Through a series of expansions and reversals on our core systems, combined with the execution of greenfield projects and strategic acquisitions, we have been able to meet the needs of producers and consumers alike. Our US Gas Transmission systems were initially designed to transport natural gas from the Gulf Coast to the supply starved northeast markets. Our asset base now has the capability to transport diverse bi-directional supply to the northeast, southeast, midwest, Gulf Coast and LNG markets on a fully subscribed and highly utilized basis.

The northeast market continues its role as a predominantly supply constrained region with steady demand. The bi-directional capabilities offered by our US Gas Transmission system allows us to deliver in an efficient manner to our regional customers. The region has seen an increase in natural gas supply due to the development of the Marcellus and Utica shales in the Appalachia region.

The southeast market is linked to multiple, highly liquid supply pools that include the Marcellus and Utica shale developments, offering consistent supply and stable pricing to a growing population of end-use customers across our multiple systems under long term, utility-like arrangements.

With connectivity to Appalachian and western Canadian supply through our systems, the midwest market has access to two of the lowest cost gas producing regions on the continent. As demand in the region is expected to continue to grow by approximately 2.0 bcf/d over the next two decades, maintaining this link will remain important. Flexibility in supply for this market is especially critical to maintaining liquidity and price stability as natural gas continues to replace coal-fired generation.

Gulf Coast demand growth is being driven by an increase in the volume of LNG exports, an ongoing wave of gas-intensive petrochemical facilities, along with power generation and additional pipeline exports to Mexico. Demand to these markets in the region is anticipated to grow by more than 23.0 bcf/d through 2040. The Gulf Coast market has been the beneficiary of low cost capacity on our assets as the relationship between supply and market centers has shifted. Such cost-effective capacity is difficult to access or replicate, offering existing shippers and transporters stability of capacity and utilization. Tide-water market access and proximity to Mexico continue to make this region a platform of global trade as pipeline and LNG exports continue their growth trajectory. The US exported over 11 bcf/d of natural gas to LNG markets, primarily from the Gulf Coast region, at the end of 2021.

Western Canada, not unlike other supply hubs, is a source of low-cost supply seeking access to premium markets in North America and globally. One of the few vital links to demand centers in the pacific northwest are our own systems in the region, which are highly utilized.

Global energy demand is expected to increase approximately 27% by 2040, according to the International Energy Agency, driven primarily by economic growth in non-OECD countries. Natural gas will play an important role in meeting this energy demand as gas consumption is anticipated to grow by approximately 23% during this period as one of the world’s fastest growing energy sources. North American exports will play a significant part in meeting global demand, underscoring the ability of our assets to remain highly utilized by shippers, and highlighting the need for incremental transportation solutions across North America. In response to these global fundamentals, we believe we are well positioned to provide value-added solutions to shippers. Opposition to natural gas development, including new pipeline projects, has been increasing in recent years. This may challenge continued growth of the North American gas market and the ability to efficiently connect supply and demand. We are responding to the need for regional infrastructure with additional investments in Canadian and US gas transportation facilities. Progress on the development and construction of our commercially secured growth projects is discussed in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

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GAS DISTRIBUTION AND STORAGE

Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge Gas Inc. (Enbridge Gas), which serves residential, commercial and industrial customers throughout Ontario. This business segment also includes natural gas distribution activities in Québec and previously included an investment in Noverco Inc. (Noverco) which was sold on December 30, 2021. Please refer to Part II. Item 8. Financial Statements and Supplementary data - Note 8 - Acquisitions and Dispositions for further details.

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ENBRIDGE GAS
Enbridge Gas is a rate-regulated natural gas distribution utility with storage and transmission services that has been in operation for 173 years. Enbridge Gas serves approximately 75% of Ontario residents via approximately 3.8 million residential, commercial and industrial meter connections.

There are three principal interrelated aspects of the natural gas distribution business in which Enbridge Gas is directly involved: Distribution, Transportation and Storage.

In 2021, Enbridge Gas implemented a voluntary RNG pilot program, whereby customers can voluntarily contribute towards the incremental cost of low carbon RNG to displace regular natural gas, and a pilot project which allows regular natural gas to be blended with H2, in an isolated portion of the existing distribution system, in an effort to gain insight into the use of H2 as a method for decarbonizing natural gas for the purpose of reducing GHG emissions.

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Distribution
Enbridge Gas’ principal source of revenue arises from distribution of natural gas to customers. The services provided to residential, small commercial and industrial heating customers are primarily on a general service basis, without a specific fixed term or fixed price contract. The services provided to larger commercial and industrial customers are usually on an annual contract basis under firm or interruptible service contracts. Under a firm contract, Enbridge Gas is obligated to deliver natural gas to the customer up to a maximum daily volume. The service provided under an interruptible contract is similar to that of a firm contract, except that it allows for service interruption at Enbridge Gas’ option primarily to meet seasonal or peak demands. The Ontario Energy Board (OEB) approves rates for both contract and general services. The distribution system consists of approximately 147,000-kilometers (91,342-miles) of pipelines that carry natural gas from the point of local supply to customers.

Customers have a choice with respect to natural gas supply. Customers may purchase and deliver their own natural gas to points upstream of the distribution system or directly into Enbridge Gas’ distribution system, or, alternatively, they may choose a system supply option, whereby customers purchase natural gas from Enbridge Gas’ supply portfolio. To acquire the necessary volume of natural gas to serve its customers, Enbridge Gas maintains a diversified natural gas supply portfolio, acquiring supplies on a delivered basis in Ontario, as well as acquiring supply from multiple supply basins across North America.

Transportation
Enbridge Gas contracts for firm transportation service, primarily with TransCanada Pipelines Limited (TransCanada), Vector and NEXUS, to meet its annual natural gas supply requirements. The transportation service contracts are not directly linked with any particular source of natural gas supply. Separating transportation contracts from natural gas supply allows Enbridge Gas flexibility in obtaining its own natural gas supply and accommodating the requests of its direct purchase customers for assignment of TransCanada capacity. Enbridge Gas forecasts the natural gas supply needs of its customers, including the associated transportation and storage requirements.

In addition to contracting for transportation service, Enbridge Gas offers firm and interruptible transportation services on its own Dawn-Parkway pipeline system. Enbridge Gas’ transmission system consists of approximately 5,500-kilometers (3,418-miles) of high-pressure pipeline and five mainline compressor stations and has an effective peak daily demand capacity of 7.6 bcf/d. Enbridge Gas’ transmission system also links an extensive network of underground storage pools at the Tecumseh Gas Storage facility and Dawn Hub (collectively, Dawn) to major Canadian and US markets, and forms an important link in moving natural gas from western Canada and US supply basins to central Canadian and northeastern US markets.

As the supply of natural gas in areas close to Ontario continues to grow, there is an increased demand to access these diverse supplies at Dawn and transport them along the Dawn-Parkway pipeline system to markets in Ontario, eastern Canada and the northeastern US. Enbridge Gas delivered 1,943 bcf of gas through its distribution and transmission system in 2021. A substantial amount of Enbridge Gas’ transportation revenue is generated by fixed annual demand charges, with the average length of a long-term contract being approximately 15 years and the longest remaining contract term being 19 years.

Storage
Enbridge Gas’ business is highly seasonal as daily market demand for natural gas fluctuates with changes in weather, with peak consumption occurring in the winter months. Utilization of storage facilities permits Enbridge Gas to take delivery of natural gas on favorable terms during off-peak summer periods for subsequent use during the winter heating season. This practice permits Enbridge Gas to minimize the annual cost of transportation of natural gas from its supply basins, assists in reducing its overall cost of natural gas supply and adds a measure of security in the event of any short-term interruption of transportation of natural gas to Enbridge Gas’ franchise areas.

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Enbridge Gas’ storage facility at Dawn is located in southwestern Ontario, and has a total working capacity of approximately 281 bcf in 34 underground facilities located in depleted gas fields. Dawn is the largest integrated underground storage facility in Canada and one of the largest in North America. Approximately 180 bcf of the total working capacity is available to Enbridge Gas for utility operations. Enbridge Gas also has storage contracts with third parties for 21 bcf of storage capacity.

Dawn offers customers an important link in the movement of natural gas from western Canadian and US supply basins to markets in central Canada and the northeast US. Dawn's configuration provides flexibility for injections, withdrawals and cycling. Customers can purchase both firm and interruptible storage services at Dawn. Dawn offers customers a wide range of market choices and options with easy access to upstream and downstream markets. During 2021, Dawn provided services such as storage, balancing, gas loans, transport, exchange and peaking services to over 200 counterparties.

A substantial amount of Enbridge Gas’ storage revenue is generated by fixed annual demand charges, with the average length of a long-term contract being approximately four years and the longest remaining contract term being 15 years.

NOVERCO
Noverco is a holding company that wholly-owns Énergir, LP (Énergir), formerly known as Gaz Metro Limited Partnership, a natural gas distribution company operating in Québec, with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in Québec and Vermont. Énergir serves approximately 525,000 residential and industrial customers and is regulated by the Québec Régie de l’énergie and the Vermont Public Utility Commission. Noverco also holds an investment in our common shares. We owned an equity interest in Noverco through ownership of 38.9% of its common shares and an investment in its preferred shares. On December 30, 2021, we sold our 38.9% non-operating minority ownership interest in Noverco to Trencap L.P. for $1.1 billion in cash.

GAZIFÈRE
We wholly own Gazifère, a natural gas distribution company that serves approximately 44,000 customers in western Québec, a market not served by Énergir. Gazifère is regulated by the Québec Régie de l’énergie.

COMPETITION
Enbridge Gas’ distribution system is regulated by the OEB and is subject to regulation in a number of areas, including rates. Enbridge Gas is not generally subject to third-party distribution competition within its franchise areas.

Enbridge Gas competes with other forms of energy available to its customers and end-users, including electricity, coal, propane and fuel oils. Factors that influence the demand for natural gas include weather, price changes, the availability of natural gas and other forms of energy, the level of business activity, conservation, legislation including the federal carbon pricing law, governmental regulations, the ability to convert to alternative fuels and other factors.

SUPPLY AND DEMAND
We expect that demand for natural gas in North America will continue to see steady annual growth over the long term with continued growth in peak day demands, however there are risks to the natural gas market that may challenge its growth prospects. Evolving customer preferences for lower-carbon fuels and more efficient technologies, combined with increasing opposition to natural gas development in North America, may reduce the markets’ ability to efficiently deploy capital to connect supply and demand. We monitor these factors closely to be able to develop our business strategy to align with shifts in customer preferences.

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We expect demand for natural gas connections in Ontario to maintain its recent growth profile due to continued population growth and with competitively priced natural gas expected to continue to provide a significant price advantage relative to alternate energy options, even with increasing carbon charges. Specific interest in natural gas connections is expected to come from communities that are not currently serviced by natural gas in Ontario.

Enbridge Gas continues to focus on promoting conservation and energy efficiency by undertaking activities focused on reducing natural gas consumption through various demand side management programs offered across all markets and sourcing supply with a smaller carbon footprint. In addition to our existing RNG programs, we are also expanding our efforts in other low-carbon supply sourcing such as Responsibly Sourced Natural Gas, and Hydrogen Gas.

The storage and transportation marketplace continues to respond to changing natural gas supply dynamics, including a recovering supply environment which was negatively impacted by the global pandemic.

Over the past decade, growth in the North American gas supply landscape, driven mainly by the development of unconventional gas resources in the Montney, Permian, Marcellus and Utica supply basins, has resulted in lower annual commodity prices and narrower seasonal price spreads. Unregulated storage values are primarily determined by the difference in value between winter and summer natural gas prices. Storage values have been relatively stable as North American natural gas supply and demand slowly returned to a more balanced position.

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RENEWABLE POWER GENERATION

Renewable Power Generation consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery, and transmission assets. In North America, assets are primarily located in the provinces of Alberta, Saskatchewan, Ontario, and Québec and in the states of Colorado, Texas, Indiana and West Virginia. We are also developing several solar self-power projects along our oil and gas rights-of-way in North America. In Europe, we hold equity interests in operating offshore wind facilities in the coastal waters of the United Kingdom and Germany, as well as interests in several offshore wind projects under construction and active development in France. Further, we are pursuing new European offshore wind development opportunities through Maple Power Ltd., a joint venture in which we hold a 50% interest.

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Combined Renewable Power Generation investments represent approximately 2,178 MW of net generation capacity. Of this amount, approximately:
1,392 MW is generated by North American wind facilities;
255 MW is generated by European offshore wind facilities;
309 MW will be generated by the Saint-Nazaire, Fécamp and Calvados Offshore Wind projects, all of which are currently under construction;
6 MW will be generated by the Provence Grand Large Floating Offshore Wind project, which secured funding in 2021 and continues to prepare onshore construction; and
93 MW is generated by North American solar facilities in operation, with an additional 97 MW in projects in early construction and under-construction.

The vast majority of the power produced from these facilities is sold under long-term Power Purchase Agreements (PPAs).

Renewable Power Generation also includes our 25% interest in the East-West Tie, a 450-MW transmission line in northwestern Ontario, which is currently under construction and is expected to reach commercial operation in the first half of 2022.

JOINT VENTURES / EQUITY INVESTMENTS
The investments in the Canadian wind and solar assets (excluding self-power) and two of the US renewable assets are held within a joint venture in which we maintain a 51% interest and which we manage and operate.

We also own interests in European offshore wind facilities through the following joint ventures:
a 24.9% interest in Rampion Offshore Wind, located in the United Kingdom;
a 25.4% interest in Hohe See Offshore and its subsequent expansion, located in Germany;
a 25.5% interest in the Saint-Nazaire Offshore Wind project, under construction in France;
a 25% interest in the Provence Grande Large Floating Offshore Wind project, in pre-construction in France;
a 17.9% interest in the Fécamp Offshore Wind project, under construction in France; and
a 21.7% interest in the Calvados Offshore Wind project, in pre-construction in France.

The ownership interest percentages in the Saint-Nazaire, Fécamp, and Calvados Offshore Wind projects reflect the sale of 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to the Canada Pension Plan Investment Board (CPP Investments) which closed in the first half of 2021.

COMPETITION
Renewable Power Generation operates in the North American and European power markets, which are subject to competition and supply and demand fundamentals for power in the jurisdictions in which they operate. The majority of revenue is generated pursuant to long-term PPAs (or has been substantially hedged). As such, the financial performance is not significantly impacted by fluctuating power prices arising from supply/demand imbalances or the actions of competing facilities during the term of the applicable contracts. However, the renewable energy sector includes large utilities, small independent power producers and private equity investors, which are expected to aggressively compete for new project development opportunities and for the right to supply customers when contracts expire.

To grow in an environment of heightened competition, we strategically seek opportunities to collaborate with well-established renewable power developers and financial partners and to target regions with commercial constructs consistent with our low risk business model. In addition, we bring to bear the expertise of completing and delivering large scale infrastructure projects.

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SUPPLY AND DEMAND
The renewable power generation network in North America and Europe is expected to grow significantly over the next 20 years due to the replacement of older fossil fuel-based sources of electricity generation in support of announced governmental carbon emissions reduction targets. Any additional governmental actions toward reducing emissions and/or increasing electrification will further accelerate renewable electricity demand growth and electrification across all sectors.

On the demand side, North American economic growth over the longer term and the continued electrification and transition to low-carbon strategies within the residential, transportation and industrial sectors are expected to drive growing electricity demand. Furthermore, voluntary GHG emissions targets are becoming increasingly expected by stakeholders, which is driving significant demand from corporate electricity end-users for clean electricity and environmental attributes. However, continued efficiency gains are expected to make the economy less energy-intensive and temper overall demand growth.

On the supply side in North America, legislation is accelerating the retirement of aging coal-fired generation, while generation from conventional nuclear power is also forecast to decline. As a result, North America requires significant new generation capacity from preferred technologies. Gas-fired and renewable energy facilities, including solar and wind (which make up the bulk of our renewable power assets), are generally the preferred sources to replace coal-fired generation due to their low carbon intensities.

The falling capital and operating costs of wind and solar, combined with their improving capacity factors, are expected to continue the ongoing trend of making renewable energy more competitive and support investment over the long-term, regardless of available government incentives. Generation from renewable sources is expected to double over the next two decades in North America. Aside from the construction of new wind and solar facilities, other growth opportunities include repowering projects to increase output from, and extending the project-life of, our existing facilities.

In Europe, the renewable energy outlook is robust. Demand for electricity is expected to gradually increase over the next two decades, driven by electrification of transportation and buildings. Energy efficiency gains will temper, but not eliminate, demand growth. Renewable power will play a significant role in the United Kingdom’s ability to meet their aggressive low-carbon and renewable energy targets, particularly offshore wind.

On the supply side, the International Energy Agency expects coal to fall by more than 90% from 2020 levels, while nuclear falls by one-third, by 2040. Over the same period, it anticipates power generation from renewable sources will more than double, including installed (onshore and offshore) wind more than doubling and photovoltaics solar power nearly tripling. We, through our European joint ventures, continue to invest in offshore wind projects in the United Kingdom, France and Germany, and to explore opportunities, to meet the growing demand.

ENERGY SERVICES

The Energy Services businesses in Canada and the US provide physical commodity marketing and logistical services to North American refiners, producers, and other customers.

Energy Services is primarily focused on servicing customers across the value chain and capturing value from quality, time, and location price differentials when opportunities arise. To execute these strategies, Energy Services transports and stores on both Enbridge-owned and third party assets using a combination of contracted long-term and short-term pipeline, storage, railcar, and truck capacity agreements.

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COMPETITION
Energy Services’ earnings are primarily generated from arbitrage opportunities which, by their nature, can be replicated by competitors. An increase in market participants entering into similar arbitrage strategies could have an impact on our earnings. Efforts to mitigate competition risk include diversification of the marketing business by transacting at the majority of major hubs in North America and establishing long-term relationships with clients and pipelines.

ELIMINATIONS AND OTHER

Eliminations and Other includes operating and administrative costs that are not allocated to business segments and the impact of foreign exchange hedge settlements. Eliminations and Other also includes new business development activities and corporate investments.

REGULATION

GOVERNMENT REGULATION
Pipeline Regulation
Our Liquids Pipelines and Gas Transmission and Midstream assets are subject to numerous operational rules and regulations mandated by governments or applicable regulatory authorities, breaches of which could result in fines, penalties, operating restrictions and an overall increase in operating and compliance costs.

In the US, our interstate pipeline operations are subject to pipeline safety laws and regulations administered by the Pipeline and Hazardous Materials Safety Administration (PHMSA), an agency within the United States Department of Transportation. These laws and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our interstate pipelines. These laws and regulations, among other things, include requirements to monitor and maintain the integrity of our pipelines and to operate them at permissible pressures.

PHMSA continues to review existing regulations and establish new regulations to support safety standards that are designed to improve and expand operations integrity management processes. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. In this climate of increasingly stringent regulation, pipeline failure or failures to comply with applicable regulations could result in reduction of allowable operating pressures as authorized by PHMSA, which would reduce available capacity on our pipelines. Should any of these risks materialize, it may have an adverse effect on our operations, capital expenditures, earnings, cash flows, financial condition and competitive advantage.

Our ability to establish transportation and storage rates on our US interstate natural gas facilities are subject to regulation by the FERC, whose rulings and policies could have an adverse impact on the ability of such pipeline and storage assets to recover their respective full cost of operating, including a reasonable rate of return. Regulatory or administrative actions by FERC such as rate proceedings, applications to certify construction of new facilities, and depreciation and amortization policies can affect our business, including decreasing tariff rates and revenues and increasing our costs of doing business.

In Canada, our pipeline operations are subject to pipeline safety regulations administered by the CER or provincial regulators. Applicable legislation and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our pipelines. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipelines.

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As in the US, several legislative changes addressing pipeline safety in Canada have recently been enacted. The changes evidence an increased focus on the implementation of management systems to address key areas such as emergency management, integrity management, safety, security and environmental protection. Other legislative changes have created authority for the CER to impose administrative monetary penalties for non-compliance with the regulatory regime it administers, as well as to impose financial requirements for future abandonment and major pipeline releases.

A key component of pipeline safety and reliability is the approach to integrity management that uses reliability targets and safety case assessments. A long history of extensive inline inspection has provided detailed knowledge of the assets in our pipeline systems. Our pipelines are assessed and maintained, in a proactive manner, such that the probability of a release is sufficiently low and that our reliability targets are met. Furthermore, the integrity management program has an independent step to check the results of our integrity assessments to validate the effectiveness of the program and to ensure that the operational risk remains as low as reasonably practicable throughout the integrity inspection and assessment cycle. As inspection technology, pipeline materials and construction practices improve with time, and new data on threats and pipeline condition are gathered, our methods of maintaining fitness for service evolves, with a strong focus on continual improvement in every aspect of integrity management.

Our pipelines also face economic regulation risk. Broadly defined, economic regulation risk is the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements or policies, including permits and regulatory approvals for both new and existing projects or agreements, upon which future and current operations are dependent. Our Mainline System and other liquids pipelines and gas transmission facilities are subject to the actions of various regulators, including the CER and the FERC, with respect to the tariffs and tolls of those pipelines. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable permits and tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on our revenues and earnings.

Gas Distribution and Storage
Our gas distribution and storage utility operations are regulated by the OEB and the Québec Régie de l’énergie, among others. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position, or amounts that would have been recorded on the Consolidated Statements of Financial Position in the absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded.

Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year incentive regulation (IR) framework using a price cap mechanism. The price cap mechanism establishes new rates each year through an annual base rate escalation at inflation less a 0.3% productivity factor, annual updates for certain costs to be passed through to customers, and where applicable, the recovery of material discrete incremental capital investments beyond those that can be funded through base rates. The IR framework includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved return on equity (ROE).

We retain dedicated professional staff and maintain strong relationships with customers, intervenors and regulators. This strong regulatory relationship continued in 2021 following OEB Decisions and Orders approving Phase 2 of Enbridge Gas’ application for 2021 rates and Phase 1 of Enbridge Gas’ application for 2022 rates. The Phase 2 Decision and Order approved the funding of $124 million in 2021 discrete incremental capital investment requested through the incremental capital module, while the Phase 1 Decision and Order approved 2022 base rate escalation under the price cap mechanism.

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Enbridge Gas continues to develop opportunities to support a low-carbon future in Ontario. In 2021, we received OEB approval of an Integrated Resource Planning (IRP) framework. The framework requires Enbridge Gas to consider facility and non-pipe demand and/or supply side alternatives (IRP alternatives) to address systems needs of its regulated operations, where certain parameters have been met. The framework will also allow Enbridge Gas to pursue an IRP alternative (or combination of IRP and facility alternative) where it is found to be in the best interest of Enbridge Gas and its customers, taking into account reliability and safety, cost-effectiveness, public policy, optimized scoping, and risk management.

Renewable Power Generation
Renewable Power Generation is subject to numerous operational rules and regulations mandated by governments or applicable regulatory authorities, breaches of which could result in fines, penalties, operating restrictions and an overall increase in operating and compliance costs.

The North American Reliability Council (NERC) is an international regulatory authority responsible for establishing and enforcing Reliability Standards to reduce risks to the reliability and security of the grid in Canada, the United States, and Mexico. It is subject to oversight from the FERC and provincial governments in Canada. The FERC has authority over many markets in the US and is tasked with ensuring safe, reliable, and secure interstate transmission of electricity, natural gas, and oil. This includes establishing reliability standards and determining certain pricing aspects of transmission development and access, among others. NERC and FERC standards and pricing decisions are also updated from time to time and could impact our operations, capital expenditures, earnings, and cash flows, though some of these impacts could be positive for our business.

At the US federal level, our Renewable Power Generation assets are subject to legislation overseen by the US Fish and Wildlife Service, which is aimed at reducing the impact of development and human activity on wildlife, along with other federal environmental permitting legislation. These federal environmental laws are subject to change from time to time which could require Enbridge to obtain new permits, update practices, or amend operations and operating expenditures.

In Canada, the Federal Government does not generally regulate the electricity sector though it has imposed a federal carbon price on other sectors via its output-based pricing system (OBPS) and may seek to impose emissions standards on the electricity sector in the future.

Our Renewable Power Generation assets in France and Germany each have federal policies in place and are subject to directives and regulations established and enforced by the European Union (EU). These include the Renewable Energy Directive (RED II most recently passed set targets through 2030), the European Green Deal, and ongoing work on financing mechanisms and transmission directives and programs. The EU is also responsible for establishing environmental protection rules and permitting standards. All of these are subject to change from time to time, which could impact our operations and related expenditures; however the EU’s general direction is to facilitate increased renewable power integration to its grid.

The United Kingdom (UK) government is responsible for establishing renewable energy and carbon pricing policies for the entire UK, as well as long-term electricity sector planning and procurement mechanisms and structure for auctions that are administered at the national level, e.g., England, Scotland, within the UK. Each country within the UK is also responsible for establishing its own environmental and permitting regulations. This process is still ongoing following Brexit and in some cases continues to result in more volatile merchant power prices; however, expanded interconnectors to Europe and policies aimed at increasing domestic renewable capacity are in progress.

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Energy Services
Energy Services is regulated by government authorities in the areas of commodity trading, import and export compliance and the transportation of commodities. Non-compliance with governing rules and regulations could result in fines, penalties and operating restrictions. These consequences would have an adverse effect on operations, earnings, cash flows, financial condition and competitive advantage. Energy Services retains dedicated professional staff and has a robust regulatory compliance program to mitigate these potential risks associated with the business.

In the US, commodity marketing is regulated by the Commodity Futures Trading Commission, the SEC, the Federal Trade Commission, the various commodity exchanges, the US Department of Justice and state regulators. The interstate marketing of electricity and natural gas is also regulated by the FERC. The provincial and territorial securities regulators similarly regulate commodity marketing within Canada and are members of the Canadian Securities Administrators. In addition, the Regional Transmission Organizations and Independent System Operators in both US and Canada regulate commodity marketing. These various regulators enforce, among other things, the prohibition of market manipulation, fraud and disruptive trading. To mitigate risks related to commodity trading, Energy Services has implemented a robust regulatory compliance program that includes targeted training.

The export of natural gas out of Alberta is regulated by the Alberta Energy Regulator. The import and export of commodities between Canada and the US is subject to regulation by the CER and the US Department of Energy, as well as customs authorities. In particular, import and export permits are required, with associated regular reporting requirements. Breaches of such import and export rules could result in an inability to perform day to day operations, and therein negatively impact the earnings of the business.

The transportation of crude oil and natural gas liquids by railcar or truck is regulated by the US Department of Transportation, Transport Canada and provincial regulation. Each jurisdiction requires compliance with security, safety, emergency management, and environmental laws and regulations related to ground transportation of commodities. Risks associated with transportation of crude or natural gas liquids include unplanned releases. In the event of a release, remediation of the affected area would be required. Energy Services engages third parties, such as the Emergency Response Assistance Canada, Chemical Transportation Emergency Center and Canadian Transport Emergency Center to assist in such remediation.

ENVIRONMENTAL REGULATION
Pipeline Regulation
Our Liquids Pipelines and Gas Transmission and Midstream assets are subject to numerous federal, state and provincial environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, water discharge and waste. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits and other approvals.

In particular, in the US, compliance with major Clean Air Act regulatory programs is likely to cause us to incur significant capital expenditures to obtain permits, evaluate off-site impacts of our operations, install pollution control equipment, and otherwise assure compliance. Some states in which we operate are implementing new emissions limits to comply with 2008 ozone standards regulated under the National Ambient Air Quality Standards. In 2015, the ozone standards were lowered even further from 75 parts per billion (ppb) to 70 ppb, which may require states to implement additional emissions regulations. The precise nature of these compliance obligations at each of our facilities has not been finally determined and may depend in part on future regulatory changes. In addition, compliance with new and emerging environmental regulatory programs may significantly increase our operating costs compared to historical levels.

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In the US, climate change action is evolving at federal, state and regional levels. The Supreme Court decision in Massachusetts v. Environmental Protection Agency in 2007 established that GHG emissions were pollutants subject to regulation under the Clean Air Act. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities but are not generally subject to limits on emissions of GHGs. The new US presidential administration has also announced that policies designed to combat climate change and reduce GHG emissions will be a key legislative and regulatory priority, and thus stricter emissions limits and air quality enforcement actions are likely. In addition, a number of states have joined regional GHG initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly focusing on the emission of methane associated with natural gas development and transmission as a source of GHG emissions. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.

For its part, Canada has reaffirmed its strong preference for a harmonized approach on climate action with that of the US. In 2019, the Government of Canada implemented a federal system of carbon pricing. The pricing applies to provinces and territories that do not have a carbon pricing system in place that meets the federal benchmark. The Canadian Net-Zero Emissions Accountability Act,which received royal assent in April 2021, requires national targets for the reduction of GHG emissions in Canada be set, with the objective of attaining net-zero emissions by 2050. As of April 2021, the federal carbon price was raised to $40 per tonne. This will increase to $65 per tonne in 2023 and rise to $170 per tonne of carbon dioxide equivalent in 2030.

Due to the speculative outlook regarding any US federal and state policies, we cannot estimate the potential effect of proposed GHG policies on our future consolidated results of operations, financial position or cash flows. However, such legislation or regulation could materially increase our operating costs, require material capital expenditures or create additional permitting, which could delay proposed construction projects.

Gas Distribution and Storage
Our Gas Distribution and Storage operations, facilities and workers are subject to municipal, provincial and federal legislation which regulate the protection of the environment and the health and safety of workers. Environmental legislation primarily includes regulation of spills and emissions to air, land and water; hazardous waste management; the assessment and management of contaminated sites; protection of environmentally sensitive areas, and species at risk and their habitat; and the reporting and reduction of GHG emissions.

Gas distribution system operation, as with any industrial operation, has the potential risk of abnormal or emergency conditions, or other unplanned events that could result in releases or emissions exceeding permitted levels. These events could result in injuries to workers or the public, adverse impacts to the environment, property damage and/or regulatory infractions including orders and fines. We could also incur future liability for soil and groundwater contamination associated with past and present site activities.

In addition to gas distribution, we also operate storage facilities and a small volume of oil and brine production in southwestern Ontario. Environmental risk associated with these facilities has the potential for unplanned releases. In the event of a release, remediation of the affected area would be required. There would also be potential for fines, orders or charges under environmental legislation, and potential third-party liability claims by any affected landowners.

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The gas distribution system and our other operations must maintain environmental approvals and permits from regulators to operate. As a result, these assets and facilities are subject to periodic inspections and/or audits. Annual reports, such as Annual Written Summary Reports for Environmental Compliance Approvals (ECAs) are submitted to the Ontario Ministry of the Environment, Conservation and Parks (MECP) and other regulators to demonstrate we are in good standing with our environmental requirements. Failure to maintain regulatory compliance could result in operational interruptions, fines, and/or orders for additional pollution control technology or environmental mitigation. As environmental requirements and regulations become more stringent, the cost to maintain compliance and the time required to obtain approvals is expected to increase.

As in previous years, in 2021, we reported operational GHG emissions, including emissions from stationary combustion, flaring, venting and fugitive sources to Environment and Climate Change Canada (ECCC), the Ontario MECP, and a number of voluntary reporting programs. In accordance with the provincial GHG regulations, stationary combustion and flaring emissions related to storage and transmission operations were verified in detail by a third-party accredited verifier with no material discrepancies found.

Enbridge Gas utilizes emissions data management processes and systems to help with the data capture and mandatory and voluntary reporting needs. Quantification methodologies and emission factors will continually be updated in our systems as required. Enbridge Gas continues to work with industry associations to refine quantification methodologies and emissions factors, as well as best management practices to minimize emissions.

In October 2018, the federal government confirmed that Ontario is subject to the federal government’s carbon pricing program, otherwise known as the Federal Carbon Pricing Backstop Program. This program consists of two components: a carbon charge levied on fossil fuels, including natural gas, and an OBPS.

The federal carbon charge took effect on April 1, 2019 at a rate of 3.91 cents/cubic meter (m3) of natural gas and is applicable to the majority of customers. Enbridge Gas is registered as a natural gas distributor with the Canada Revenue Agency and remits the federal carbon charge on a monthly basis. The charge increases annually on April 1 of each year by 1.96 cents/m3, rising up to 9.79 cents/m3 in 2022. In December 2020, the federal government announced plans to increase the federal carbon price by $15 per tonne each year in 2023, rising to $170 per tonne of carbon dioxide equivalent in 2030. Enbridge Gas estimates that this will equate to a federal carbon charge on natural gas of approximately 33.31 cents/m3 in 2030. Enbridge Gas applies for approval from the OEB on an annual basis to pass through federal carbon charges.

The OBPS component came into effect on January 1, 2019. Under OBPS, a registered facility has a compliance obligation for the portion of their emissions that exceeds their annual facility emissions limit, which is calculated based on the sector specific output-based standard and annual production. Enbridge Gas is registered with ECCC as an emitter in the OBPS program and has an annual compliance obligation associated with the combustion and flaring emissions associated with its natural gas pipeline transmission system. As a registered facility under OBPS,Enbridge Gas submitted an annual report along with the required verification report from an accredited third-party verifier who found no material misstatements. Enbridge Gas is required to remit payment for facility emissions that exceed its annual facility emissions limit. Due to COVID-19, ECCC delayed the payment deadline for the 2019 compliance obligation from December 15, 2020 to April 15, 2021. Enbridge Gas made payment for the 2019 compliance obligation in March 2021 and for the 2020 compliance obligation in November 2021.

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In September 2020, Ontario and the federal government announced that the federal government has accepted that Ontario’s Emission Performance Standards (EPS) will replace the federal OBPS for industrial facilities. In March 2021, the federal government announced that the federal OBPS will stand down in Ontario at the end of 2021 and Ontario will transition to the EPS effective January 1, 2022. In September 2021, the Greenhouse Gas Pollution Pricing Act was amended to remove Ontario as a covered province effective January 1, 2022. Beginning January 1, 2022, Enbridge Gas will have a compliance obligation under the EPS program for its facility-related emissions, as well as the federal carbon charge for its customer-related emissions.

HUMAN CAPITAL RESOURCES

WORKFORCE SIZE AND COMPOSITION
As at December 31, 2021, we had approximately 10,900 regular employees, including approximately 1,500 unionized employees across our North American operations. This total rises to nearly 13,000 if temporary employees and contractors are included. We have a strong preference for direct employment relationships but where we have collectively bargained-for employees, we have mature working relationships with our labor unions and the parties have traditionally committed themselves to the achievement of renewal agreements without a work stoppage.

SAFETY
We believe all injuries, incidents and occupational illnesses are preventable. Our overall focus on employee and contractor safety, including through the COVID-19 pandemic, continues to result in strong performance compared against industry benchmarks and we are actively engaged in continuous improvement exercises as we pursue our goal of zero incidents.

DIVERSITY AND INCLUSION
To ensure our workforce is reflective of the communities where we operate, we have pursued efforts to increase the representation of women, underrepresented ethnic and racial groups, people with disabilities and veterans. In 2021 we set diversity representation goals and shared these goals with employees and external stakeholders. Consistent with our culture, we remain committed to open, two-way dialogue related to our goals, enhancing transparency and accountability for all stakeholders.

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In 2021, we added Inclusion to our core values of Safety, Integrity and Respect to demonstrate this commitment. We are building an organization where people feel safe and welcome and have the opportunity to thrive and grow based on merit. As part of our evolving ESG strategy, we created a tighter link between our success and the workforce related ESG measures – including safety, emissions reduction efforts and diversity & inclusion – that enable it. As a result, beginning in 2021, key metrics in these areas are embedded in our scorecards and directly impact compensation.

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PRODUCTIVITY AND DEVELOPMENT
We continually invest in our people’s personal and professional development because we recognize their success is our success. Every year, employees are provided access to a range of development and re-skilling opportunities through a variety of channels, including: extensive catalog of self-directed learning (10,000+ external courses plus proprietary Enbridge University courses); on-the-job learning opportunities and rotational assignments; curated leadership development programs; educational reimbursement; and developmental relationships with mentors through our formal mentor-protégé matching program.

EXECUTIVE OFFICERS

The following table sets forth information regarding our executive officers as at February 11, 2022:
NameAgePosition
Al Monaco62President & Chief Executive Officer
Vern D. Yu55Executive Vice President & Chief Financial Officer
Colin K. Gruending52Executive Vice President & President, Liquids Pipelines
Cynthia L. Hansen57Executive Vice President & President, Gas Distribution and Storage
Byron C. Neiles56Executive Vice President, Corporate Services
Robert R. Rooney65Executive Vice President & Chief Legal Officer
William T. Yardley57Executive Vice President & President, Gas Transmission and Midstream
Matthew Akman54Senior Vice President, Strategy, Power & New Energy Technologies
Allen C. Capps51Senior Vice President, Corporate Development & Energy Services

Al Monaco was appointed President and Chief Executive Officer on October 1, 2012. Mr. Monaco is also a member of the Enbridge Board of Directors.

Vern D. Yu was appointed Executive Vice President and Chief Financial Officer on October 1, 2021, with oversight for all of Enbridge’s financial affairs including investor relations, financial reporting, financial planning, treasury, tax, insurance, risk and audit management functions as well as implementation of our ERP transformation system. Previously, Mr. Yu served as Executive Vice President and President, Liquids Pipelines and prior to that served as President and Chief Operating Officer for Liquids Pipelines and as Executive Vice President and Chief Development Officer. Effective March 1, 2022, Mr. Yu will be appointed as Executive Vice President, Corporate Development and Chief Financial Officer.

Colin K. Gruending was appointed Executive Vice President and President, Liquids Pipelines on October 1, 2021. Mr. Gruending is responsible for the overall leadership and operations of Enbridge’s Liquids Pipelines business. Previously, he served as our Executive Vice President and Chief Financial Officer and as Senior Vice President, Corporate Development and Investment Review.

Cynthia L. Hansen was appointed Executive Vice President and President, Gas Distribution and Storage, on June 1, 2019. Ms. Hansen is responsible for the overall leadership and operations of Enbridge Gas, following the amalgamation of Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas), as well as Gazifère. Previously, our Executive Vice President, Utilities and Power Operations, Ms. Hansen is also the Executive Sponsor for Asset and Work Management Transformation across Enbridge, working with other business unit leaders. Effective March 1, 2022, Ms. Hansen will be appointed as the Executive Vice President and President of Gas Transmission and Midstream and Michele E. Harradence will be appointed as Senior Vice President and President, Gas Distribution and Storage. Ms. Harradence most recently held the role of Senior Vice President and Chief Operations Officer, Gas Transmission and Midstream.

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Byron C. Neiles was appointed Executive Vice President, Corporate Services on May 2, 2016. Mr. Neiles has oversight of our information technology, human resources, real estate, supply chain management, safety, environment, land & right-of-way, and public affairs, communications and sustainability functions.

Robert R. Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017. Mr. Rooney leads our legal, ethics and compliance, security and aviation teams across the organization.

William T. Yardley was named Executive Vice President and President, Gas Transmission and Midstream on February 27, 2017. Mr. Yardley was previously President of Spectra Energy Corp's (Spectra Energy) US Transmission and Storage business, leading the business development, project execution, operations and environment, health and safety efforts associated with Spectra Energy’s US portfolio of assets. Mr. Yardley will retire on May 31, 2022.

Matthew Akman was appointed Senior Vice President, Strategy & Power on June 1, 2019 and he is currently Senior Vice President, Strategy, Power & New Energy Technologies. He is responsible for the corporate strategic planning process and all renewable power operations and development globally, as well as for our New Energy Technologies team formed in 2021. Mr. Akman joined Enbridge in early 2016 as our head of Corporate Strategy and also previously held responsibilities for Corporate Development and Investor Relations.

Allen C. Capps was appointed Senior Vice President, Corporate Development and Energy Services in September 2020. He is responsible for capital allocation, investment review, corporate business development including Mergers & Acquisitions and Energy Services. Prior to assuming his current role, Mr. Capps served as Senior Vice President, Corporate Development and Investment Review. Mr. Capps has also served as Senior Vice President and Chief Accounting Officer and before that Vice President and Controller of Spectra Energy. Effective March 1, 2022, Mr. Capps will be appointed as the Senior Vice President and Chief Commercial Officer of Gas Transmission & Midstream.

ADDITIONAL INFORMATION

Additional information about us is available on our website at www.enbridge.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. The aforementioned information is made available in accordance with legal requirements and is not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K. We make available free of charge, through our website, annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as well as proxy statements, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Reports, proxy statements and other information filed with the SEC may also be obtained through the SEC’s website (www.sec.gov).

ENBRIDGE GAS INC.
Additional information about Enbridge Gas can be found in its annual information form, financial statements and management's discussion and analysis (MD&A) for the year ended December 31, 2021, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Enbridge Gas and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

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ENBRIDGE PIPELINES INC.
Additional information about Enbridge Pipelines Inc. (EPI) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2021, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to EPI and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

WESTCOAST ENERGY INC.
Additional information about Westcoast can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2021, which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Westcoast and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

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ITEM 1A. RISK FACTORS

The following risk factors could materially and adversely affect our business, operations, financial results, market price or value of our securities. This list is not exhaustive, and we place no priority or likelihood based on order of presentation or grouping under sub-captions.

RISKS RELATED TO CLIMATE CHANGE

Climate change risks could adversely affect our business, operations and financial results, and these effects could be material.
Climate change presents both physical and transition risks to our organization. A summary of these risks is discussed below.Given the reconciliationinterconnected nature of climate impacts, however, we also discuss these risks within the context of other risks impacting Enbridge throughout Item 1A - Risk Factors. Climate change and its associated impacts may increase our exposure to, and magnitude of, the other risks identified in Item 1A - Risk Factors. Our business, financial condition, results of operations, cash flows, reputation, access to and cost of capital or insurance, business plans or strategy may all be adversely impacted as a result of climate change and its associated impacts.

PHYSICAL RISKS
Physical risks relate to the physical impacts of climate change. These risks could damage our assets or affect the safety and reliability of our operations.

Climate change could result in extreme variability in weather patterns, such as increased frequency and severity of extreme weather events, heavy snowfall, heavy rainfall, floods, landslides, fires, hurricanes, tropical storms, ice storms, rising mean temperature and sea levels, and long-term changes in precipitation patterns. Our assets and operations are exposed to potential interruption or damage from these kinds of events, and we may also experience reduced access to our assets or increased risk of loss of life or injury or damage to property and the environment. We have experienced operational interruptions and damage to our assets from such weather events in the past, and we expect to experience climate related physical risks in the future, potentially with increasing frequency or severity. Operational risk is intensified by changing climate and more extreme weather events. Any of these physical risks could result in substantial losses for which our insurance may not be sufficient or available and for which we may bear a part or all of the cost.

TRANSITION RISKS
Transition risks relate to the transition to a lower-emission economy, which may increase our cost of operations, impact our business plans, and influence stakeholder decisions about our company, each of which could adversely impact our strategic plan, business, operations or financial results. These transition risks include:

Policy and legal risks
Foreign and domestic governments continue to evaluate and implement policy, legislation, and regulations focused on reducing GHG emissions, promoting adaptation to climate change, transitioning to a low-carbon economy, and disclosure of climate-related matters. Such policies, laws and regulations vary at the federal, state, provincial and municipal levels in which Enbridge operates and can be highly variable and subject to change. It is expected that further investments will be required to meet new regulatory requirements. In addition, in recent years there has been an increase in climate and disclosure-related litigation against governments as well as companies involved in the energy industry. There is no assurance that our company will not be impacted by such litigation.

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Technology risks
Our success in executing our strategic plan, including our role in the transition to a lower-carbon economy, and attaining our GHG emissions reduction goals and targets, depends, in part, on technology (including technology still under development), innovation and continued diversification with renewable power and other low carbon energy infrastructure as well as modernization of our infrastructure to reduce GHG emissions. Achieving our GHG emissions reductions goals and targets could require significant capital expenditures and resources, with the potential that the costs required to achieve our goals and targets materially differ from our original estimates and expectations. Similarly, there is a risk that emissions reduction technology – like battery storage, CCS or direct air capture – do not materialize as expected, making it more difficult to reduce emissions.

Market risks
Climate change concerns, increase in demand for low-carbon and zero-emissions energy, alternative and new energy sources and technologies, changing customer behavior and reduced energy consumption could impact the demand for our services or securities. The pace and scale of the transition to a lower carbon economy may pose a climate-related transition risk if Enbridge diversifies either too quickly or too slowly. Similarly, uncertainty in market signals, such as abrupt and unexpected shifts in energy costs and demands, including due to climate change concerns, can impact revenue through reduced throughput volumes on our pipeline transportation systems.

Reputationalrisks
We have long been committed to strong ESG practices and performance, and in November 2020, we introduced a set of ESG goals to strengthen transparency and accountability. We have set GHG emissions reduction goals and a strategic priority to adapt to the energy transition over time. If we are not able to achieve our GHG emissions reduction goals, we are not able to meet future climate, emissions or other reporting requirements of regulators, or we are not able to meet or manage current and future expectations and issues important to investors or other stakeholders, including those related to climate change, it could negatively impact our reputation and our business, operations or financial results.

RISKS RELATED TO OPERATIONAL DISRUPTION OR CATASTROPHIC EVENTS

Pipeline operations involve numerous risks that may adversely affect our business, financial results and the environment.
Operation of complex pipeline systems, gathering, treating, storing and processing operations involves many risks, hazards and uncertainties.

These operational risks include adverse weather conditions, natural disasters, accidents, the breakdown or failure of equipment or processes, and the performance of the facilities below expected levels of capacity and efficiency and catastrophic events. Climate change presents physical risks relating to the physical impacts of climate change, which can affect the safety and reliability of our operations. Climate change could result in extreme variability in weather patterns, such as increased frequency and severity of extreme weather events, extreme hot and cold weather, heavy snowfall, heavy rainfall, floods, landslides, fires, hurricanes, tropical storms, ice storms, rising mean temperature and sea levels, and long-term changes in precipitation patterns.

Our assets and operations are exposed to potential interruption or damage from these kinds of events, and we may also experience reduced access to our assets, increased risk of loss of life or injury, damage to our property and our assets, environmental pollution or impairment of our operations. These kinds of events could also result in rupture or release of product from our pipeline systems and facilities. Such events could result in substantial losses for which insurance may not be sufficient or available and for which we may bear a part or all of the cost. Operational risk is also intensified by changing climate and more extreme weather events.

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An environmental incident is an event that may cause environmental harm and could lead to an increased cost of operating and insuring our assets, thereby negatively impacting earnings. An environmental incident could have lasting reputational impacts and could impact our ability to work with various stakeholders. For pipeline and storage assets located near populated areas, including residential communities, commercial business centers, industrial sites and other public gathering locations, the level of damage resulting from these events could be greater.

We have experienced such events in the past, including in 2010 on Lines 6A and 6B of the Lakehead System; in October 2018 at the BC Pipeline T-South system; in January 2019, August 2019 and May 2020 at the Texas Eastern Pipeline; impacts from the winter storm in February 2021 in Texas and from wildfires in July 2021 and flooding in November 2021 in BC. We have incurred and expect to continue to incur significant costs in preparing for or responding to operational risks and events. We expect to continue to experience climate related physical risks, potentially with increasing frequency and severity, and we cannot guarantee that we will not experience catastrophic or other events in the future. In addition, we could be subject to litigation and significant fines and penalties from regulators in connection with any such events.

A service interruption could have a significant impact on our operations, and negatively impact financial results, relationships with stakeholders and our reputation.
A service interruption due to a major power disruption, curtailment of commodity supply, operational incident, availability of gas supply or distribution or other reasons could have a significant impact on our operations and negatively impact financial results, relationships with stakeholders, our reputation or the safety of our end customers. Service interruptions that impact our crude oil and natural gas transportation services can negatively impact shippers’ operations and earnings as they are dependent on our services to move their product to market or fulfill their own contractual arrangements. We have experienced, and may again experience, service interruptions including in connection with the kinds of operational incidents referred to in the previous risk factor.

Our operations involve safety risks to the public and to our workers and contractors.
Several of our pipelines and distribution systems and related assets are operated in close proximity to populated areas and a major incident could result in injury or loss of life to members of the public. In addition, given the natural hazards inherent in our operations, our workers and contractors are subject to personal safety risks. A public safety incident or an injury or loss of life to our workers or contractors, which we have experienced in the past and, despite the precautions we take, may experience in the future, could result in reputational damage to us, material repair costs or increased costs of operating and insuring our assets.

Cyber-attacks or security breaches could adversely affect our business, operations or financial results.
Our business is dependent upon information systems and other digital technologies for controlling our plants, pipelines and other assets, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. A security breach of our network or systems, or the network or systems of our third-party vendors, could result in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store and distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we and some of our vendors collect and store sensitive data in the ordinary course of our business, including personal information of our employees and residential gas distribution customers as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders.

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Cybersecurity risks have increased in recent years as a result of the proliferation of new technologies and the increased sophistication, magnitude and frequency of cyber-attacks and data security breaches, as well as due to international and national political factors. Because of the critical nature of our infrastructure and our use of information systems and other digital technologies to control our assets, we face a heightened risk of cyber-attacks. New cybersecurity regulations have been recently implemented resulting in additional regulatory oversight and compliance requirements.

During the normal course of business, we have experienced and expect to continue to experience attempts to gain unauthorized access, compromise our information systems or to disrupt our operations through cyber-attacks or security breaches, although none to our knowledge have had a material adverse effect on our business, operations or financial results. Despite our security measures, our information systems or those of our vendors are expected to become the target of further cyber-attacks or security breaches which could compromise our systems, affect our ability to correctly record, process and report transactions, result in the loss of information, or cause operational disruption. As a result of a cyber-attack or security breach, we could also be liable under laws that protect the privacy of personal information, subject to regulatory penalties, incur additional costs for remediation, litigation or other costs, all of which could materially adversely affect our reputation, business, operations or financial results.

Pandemics, epidemics or disease outbreaks, such as the COVID-19 pandemic, may adversely affect local and global economies and our business, operations or financial results.
Disruptions caused by pandemics, epidemics or disease outbreaks, in locations in which we operate or globally, could materially adversely affect our business, operations, financial results and forward-looking expectations.

In response to the rapid global spread of COVID-19, governments continue to enact emergency measures to combat the spread of the virus. These measures include restrictions on business activity and travel, as well as requirements to isolate or quarantine. Certain of our operations and projects have been deemed essential services in critical infrastructure sectors and are currently exempt from certain business activity restrictions. COVID-19 and government responses have interrupted business activities and supply chains, disrupted travel, and contributed to significant volatility in the financial and commodity markets.

Given the ongoing and dynamic nature of the COVID-19 pandemic, further impacts will depend on future developments and factors outside of our control, which are uncertain, evolving and cannot be predicted, including new information which may emerge concerning the severity or duration of this pandemic (including new COVID-19 strains and the efficacy of vaccines) and actions taken by governments and others to contain or end the COVID-19 pandemic or its impact. Such developments include disruptions, which have had or may have an adverse effect on our customers, suppliers, regulators, business, operations and financial results.

There can be no assurance that our strategies to address potential disruptions will mitigate these risks or the adverse impacts to our business, operations and financial results. In addition, disruptions related to the COVID-19 pandemic have had, or could continue to have, the effect of heightening many of the other risks described in this Item 1A. Risk Factors.

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Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war, and other civil unrest or activism could adversely affect our business, operations or financial results.
Terrorist attacks and threats (which may take the form of cyber-attacks), escalation of military activity or acts of war, or other civil unrest or activism may have significant effects on general economic conditions and may cause fluctuations in consumer confidence and spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the US, or Canada, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targets in the US and Canada. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced demand for our products and services, increased legislation or denial or delay of permits and rights-of-way. Finally, the disruption or a significant increase in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could adversely affect our business, operations or financial results.

RISKS RELATED TO OUR BUSINESS AND INDUSTRY

There are utilization risks with respect to our assets.
With respect to our Liquids Pipelines assets, we may be exposed to throughput risk on the Canadian Mainline depending upon the tolling framework we adopt for that system, and we are exposed to throughput risk under certain tolling agreements applicable to other liquids pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, regulatory restrictions, maintenance and operational incidents on our system and upstream or downstream facilities and increased competition can all impact the utilization of our assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative and new energy sources and technologies, and global supply disruptions outside of our control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines.

With respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue to change due to shifts in regional production and consumption. These shifts can lead to fluctuations in commodity prices and price differentials, resulting in oversupply of pipeline takeaway capacity in some areas and an adverse effect to the utilization of our systems. Other factors affecting system utilization include operational incidents, regulatory restrictions, system maintenance, and increased competition.

With respect to our Gas Distribution and Storage assets, customers are billed on both a fixed charge and volumetric basis and our ability to collect the total revenue requirement (the cost of providing service, including a reasonable return to the utility) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of our Gas Distribution customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continue to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Even in those circumstances where we attain our respective total forecast distribution volume, our Gas Distribution business may not earn its expected ROE due to other forecast variables, such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector. Our Gas Distribution business remains at risk for the actual versus forecast large volume contract commercial and industrial volumes.

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With respect to our Renewable Power Generation assets, earnings from these assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Renewable Power Generation projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year-to-year and from season-to-season. Any prolonged reduction in wind or solar resources at any of the Renewable Power Generation facilities could lead to decreased earnings and cash flows for us. Additionally, inefficiencies or interruptions of Renewable Power Generation facilities due to operational disturbances or outages resulting from weather conditions or other factors, could also impact earnings.

Our assets vary in age and were constructed over many decades which may cause our inspection, maintenance or repair costs to increase in the future.
Our pipelines vary in age and were constructed over many decades. Pipelines are generally long-lived assets, and pipeline construction and coating techniques have changed over time. Depending on the era of construction, some assets require more frequent inspections, which could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our business, operations or financial results.

Competition may result in a reduction in demand for our services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected.
We face competition from competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada, the US and internationally and from proposed pipelines that seek to access markets currently served by our liquids pipelines. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. We also face competition from alternative storage facilities. Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The natural gas transported in our business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Renewable Power Generation business faces competition in the procurement of long-term power purchase agreements and from other fuel sources in the markets in which we operate. Competition in all of our businesses, including competition for new project development opportunities, could have a negative impact on our business, financial condition or results of operations.

Execution of our projects subjects us to various regulatory, operational and market risks that may affect our financial results.
Our ability to successfully bring our secured capital growth program into service is exposed to risks including:

the ability to obtain or amend necessary approvals and permits from governments and regulatory agencies on a timely basis and with acceptable terms and conditions and to maintain those issued approvals and permits and satisfy the terms and conditions imposed therein;
opposition by third parties, physical protests, interference with or damage to our property or infrastructure, litigation or increased execution and stakeholder engagement complexity;
new or incremental changes in federal, state, provincial and local laws and regulations after projects are sanctioned;
inflationary pressures on labor, materials and equipment, which have decreased price predictability;
bottlenecked global supply chains and logistics, which have increased delivery times of materials and equipment;
timely acquisition or renewal of rights-of-way or land rights with acceptable terms and conditions;
extreme weather events (e.g. hurricanes, forest fires, floods); or
contractor or supplier non-performance, weather, geological or other factors beyond our control.

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Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated cost.

New projects may not achieve their expected investment return, which could affect our financial results, reputation and hinder our ability to secure future projects. Recent projects that have experienced various degrees of impacts include the US L3R Program that was placed into service in the third quarter of 2021, Line 5 projects (tunnel and reroute), Texas Eastern Modernization, East-West Tie and Offshore Wind. For additional discussion of specific proceedings that could affect our operations and financial results, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates.

Changing expectations from stakeholders regarding ESG practices and climate change or erosion of stakeholder trust or confidence could damage our reputation and influence actions or decisions about our company and industry and have negative impacts on our business, operations or financial results.
Companies across all sectors and industries are facing changing expectations or increasing scrutiny from stakeholders related to their approach to ESG matters of greatest relevance to their business and to their stakeholders. For energy companies, climate change, safety, stakeholder and Indigenous relations remain primary focus areas, while other environmental elements such as biodiversity are ascendant; changing expectations of our practices and performance across these and other ESG areas may impose additional costs or create exposure to new or additional risks.

Our operations, projects and growth opportunities require us to have strong relationships with key stakeholders, including local communities, Indigenous groups and communities and other groups directly impacted by our activities, as well as governments and government agencies, investor advocacy groups, institutional investors, investment funds, financial institutions, insurers and others, which are increasingly focused on ESG practices.

Enhanced public awareness of climate change has driven an increase in demand for low-carbon and zero-emissions energy. Enbridge has a long history of diversifying its portfolio of businesses to align with the mix of energy that people need and want. However, the pace and scale of the transition to a lower emissions economy may pose a climate-related transition risk if Enbridge diversifies either too quickly or too slowly. Similarly, unexpected shifts in energy demands, including due to climate changes concerns, can impact revenue through reduced throughput volumes on our pipeline transportation system.

We have long been committed to strong ESG practices, performance and reporting, and in late 2020 introduced a set of ESG goals to strengthen transparency and accountability. The goals include increasing diversity and inclusion within our organization and reducing emissions from our operations to net zero by 2050, with corporate and business unit action plans aligned to our strategic priority to adapt to the energy transition over time. Given elevated long-term risks associated with climate change, there have also been efforts in recent years by the investment community, including increased engagement with companies on climate change and decreasing the carbon intensity of their portfolios. If we are not able to achieve our GHG emissions reduction goals, are not able to meet future climate, emissions or other reporting requirements of regulators, or are not able to meet or manage current and future expectations or issues important to investors or other stakeholders including those related to climate change, it could negatively impact stakeholder trust and confidence, our reputation, and our business, operations or financial results, including:

loss of business;
loss of ability to secure growth opportunities;
delays in project execution;
legal action, such as the legal challenges to the operation of Line 5 in Michigan and Wisconsin;
increased regulatory oversight;
loss of ability to obtain and maintain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms;
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impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms;
changing investor sentiment regarding investment in the oil and gas industry or our company;
restricted access to and cost of capital and insurance; and
loss of ability to hire and retain top talent.

We are also exposed to the risk of higher costs, delays, project cancellations, new restrictions or the cessation of operations of existing pipelines due to increasing pressure on governments and regulators. Recent judicial decisions have increased the ability of groups to make claims and oppose projects in regulatory and legal forums. In addition to issues raised by groups focused on particular project impacts, we and others in the energy and pipeline businesses are facing organized opposition to oil and gas extraction and shipment of oil and gas products.

Our forecasted assumptions may not materialize as expected, including on our expansion projects, acquisitions and divestitures.
We evaluate expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, and changes in cost estimates, project scoping and risk assessment could result in a loss of our profits.Similarly, uncertainty in market signals, such as abrupt and unexpected shifts in energy costs and demands, as we saw in 2020 resulting from the COVID-19 pandemic, have impacted, and may in the future impact, revenue through reduced throughput volumes on our pipeline transportation system.

Our insurance coverage may not be sufficient to cover our losses in the event of an accident, natural disaster or other hazardous event.
Our operations are subject to many hazards inherent in our industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause, and in some cases have caused, personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We maintain a comprehensive insurance program for us, our subsidiaries and certain of our affiliates to mitigate the financial impacts arising from these hazards. This program includes insurance coverage in types and amounts and with terms and conditions that are generally consistent with coverage customary for our industry; however, insurance does not cover all events in all circumstances.

In the unlikely event that multiple insurable incidents that in the aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among our entities on an equitable basis based on an insurance allocation agreement among us and our subsidiaries. Additionally, even with insurance, if any natural disaster or other hazardous event leads to a catastrophic interruption in operations, we may not be able to restore operations without significant interruption.

We are exposed to the credit risk of our customers.
We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy or provide us security to satisfy credit concerns. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. It is possible that customer payment defaults, if significant, could adversely affect our earnings and cash flows.

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Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our risk management policies could adversely affect our business, operations or financial results.
We use financial derivatives to manage risks associated with changes in foreign exchange rates, interest rates, commodity prices and our share price to reduce volatility of our cash flows. Based on our risk management policies, all of our financial derivatives are associated with an underlying asset, liability and/or forecasted transaction and not intended for speculative purposes.

These policies cannot, however, eliminate all risk including unauthorized trading. Although this activity is monitored independently by our risk management function, we can provide no assurance that we will detect and prevent all unauthorized trading and other violations, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could adversely affect our business, operations or financial results.

Our business requires the retention and recruitment of a skilled and diverse workforce, and difficulties in recruiting and retaining our workforce could result in a failure to implement our business plans.
Our operations and management require the retention and recruitment of a skilled and diverse workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry, and for some jobs the broader labor market, for this skilled workforce. If we are unable to retain current employees and/or recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.

Our transformation projects may fail to fully deliver anticipated results.
We launched projects starting in 2016 to transform various processes, capabilities and reporting systems infrastructure to continuously improve effectiveness and efficiency across the organization and are subject to transformation project risk with respect to these projects. Such projects, some of which will continue beyond 2022, are subject to transformation project risk. Transformation project risk is the risk that modernization projects carried out by us and our subsidiaries do not fully deliver anticipated results due to insufficiently addressing the risks associated with project execution and change management. This could result in negative financial, operational and reputational impacts.

Our business is undergoing significant changes driven by technological advancements and the energy transition, which could impact our strategic plan, business, operations or financial results.
Our success in executing our strategic plan, including our role in the transition to a low-carbon economy, and attaining our GHG emissions reduction goals and targets depends, in part, on technology (including technology still under development), innovation and continued diversification with renewable power and other low carbon energy infrastructure as well as modernization of our infrastructure to reduce GHG emissions, all of which could require significant capital expenditures and resources. Public policy relating to climate change can drive investment in lower-emissions technologies which could impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines.

Our Liquids Pipelines growth rate and results may be directly and indirectly affected by commodity prices and government policy.
This intervention had a negligible impact on the Mainline System throughput, as enough inventory existed to meet refinery customer needs and service our favorable markets. Wide commodity price basis between Western Canada and global tidewater markets have negatively impacted producer netbacks and margins in the past years that largely resulted from pipeline infrastructure takeaway capacity from producing regions in Western Canada and North Dakota which are operating at capacity. A protracted long-term outlook for low crude oil prices could result in delay or cancellation of future projects. Effective December 31, 2021, the Government of Alberta lifted the oil production curtailment that was imposed in December 2018.

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The tight conventional oil plays of Western Canada, the Permian basin, and the Bakken region of North Dakota have short cycle break-even time horizons, typically less than 24 months, and high decline rates that can be well managed through active hedging programs and are positioned to react quickly to market signals. Accordingly, during periods of comparatively low prices, drilling programs, unsupported by hedging programs, will be reduced and as such supply growth from tight oil basins may be lower, which may impact volumes on our pipeline systems.

Our Energy Services and Gas Transmission and Midstream results may be adversely affected by commodity price volatility.
Within our US Midstream assets, through our investments in DCP Midstream and Aux Sable, we are engaged in the businesses of gathering, treating and processing natural gas and natural gas liquids. The financial results of these businesses are directly impacted by changes in commodity prices.

Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Lower commodity prices due to changing market conditions could limit margin opportunities and impede Energy Services' ability to cover capacity commitments.

We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and cost effective access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating.
A significant portion of our consolidated asset base is financed with debt. The maturity and repayment profile of debt used to finance investments often does not correlate to cash flows from assets. Accordingly, we rely on access to both short-term and long-term capital markets as a source of liquidity for capital requirements not satisfied by cash flows from operations and to fund investments originally financed through debt. Our senior unsecured long-term debt is currently rated investment-grade by various rating agencies. If the rating agencies were to rate us or our rated subsidiaries below investment-grade, our borrowing costs would increase, perhaps significantly. Consequently, we would likely be required to pay a higher interest rate in future financings and our potential pool of investors and funding sources could decrease.

We maintain revolving credit facilities to provide back-up for commercial paper programs for borrowings and/or letters of credit at various entities. These facilities typically include financial covenants and failure to maintain these covenants at a particular entity could preclude that entity from issuing commercial paper or letters of credit or borrowing under the revolving credit facility, which could affect cash flows or restrict business. Furthermore, if our short-term debt rating were to be downgraded, access to the commercial paper market could be significantly limited. Although this would not affect our ability to draw under our credit facilities, borrowing costs could be significantly higher.

If we are not able to access capital at competitive rates, our ability to finance operations and implement our strategy may be affected. An inability to access capital may limit our ability to pursue enhancements or acquisitions that we may otherwise rely on for future growth. Any downgrade or other event negatively affecting the credit ratings of our subsidiaries could make their costs of borrowing higher or access to funding sources more limited, which in turn could increase our need to provide liquidity in the form of capital contributions or loans to such subsidiaries, thus reducing the liquidity and borrowing availability of the consolidated group.

RISKS RELATED TO GOVERNMENT REGULATION AND LEGAL RISKS

Many of our operations are regulated and failure to secure timely regulatory approval for our proposed projects, or loss of required approvals for our existing operations, could have a negative impact on our business, operations or financial results.
The nature and degree of regulation and legislation affecting energy companies in Canada and the US have changed significantly in recent years.

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In Canada, the passing of the Canadian Energy Regulator Act and the Impact Assessment Act under Bill C-69, which came into force on August 28, 2019, adds steps in the regulatory process and extends overall timelines associated with regulatory approvals for new projects which trigger a federal impact assessment. Changes to the BC regulatory framework have also been made, including a new Environmental Assessment Act, which came into force in December 2019, affecting provincially-regulated projects in a similar manner as those that are federally-regulated. Within the US and in Canada, pipelines companies continue to face opposition from anti-pipeline activists, Indigenous and tribal groups and communities, citizens, environmental groups and politicians concerned with either the safety of pipelines or environmental effects. In the US, several federal agencies made changes to regulations that were designed to streamline permitting, including changes that the Environmental Protection Agency made in June 2020 to regulations implementing Section 401 of the Clean Water Act and the July 2020 Council on Environmental Quality revisions to regulations implementing the National Environmental Policy Act. These and many other regulations adopted during the previous US presidential administration are not only being challenged in multiple courts, but have now been expressly targeted for rollback by the new US administration, which is expected to modify or reverse the regulations.

These actions could adversely impact permitting of a wide range of energy projects. We may not be able to obtain or maintain all required regulatory approvals for our operating assets or development projects. If there is a delay in obtaining any required regulatory approvals, if we fail to obtain or comply with them, or if laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs.

Our operations are subject to numerous environmental laws and regulations, including those relating to climate change and GHG emissions and climate-related disclosure, as well as internal initiatives to reduce GHG emissions, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans, or expose us to environmental liabilities.
We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste.

Foreign and domestic governments continue to evaluate and implement policy, legislation, and regulations focused on restricting GHG emissions, promoting adaptation to climate change and the transition to a low-carbon economy, and disclosure of climate-related matters. Such policies, laws and regulations vary at the federal, state, and provincial levels in which Enbridge operates and can be highly variable and subject to change. International multilateral agreements, the obligations adopted thereunder, increasing physical impacts of climate change, changing political and public opinion and legal challenges concerning the adequacy of climate-related policy brought against governments and corporations, among other factors, are expected to accelerate the implementation of these measures.

Enbridge is required to adhere to a number of implicit and explicit carbon-pricing mechanisms. These mechanisms may present climate-related transition risk to our business strategy, impacting both commodity demand and the overall energy mix we deliver.

Failure to comply with environmental laws and regulations and failure to secure permits necessary for our operations may result in the imposition of fines, penalties and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations, including those related to climate change and GHG emissions, could result in a material increase in our cost of compliance with such laws and regulations, such as costs to monitor and report our emissions and install new emission controls to reduce emissions. We may not be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities. Efforts to regulate or restrict GHG emissions could also drive down demand for the products we transport.

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We may not be able to obtain or maintain all required environmental regulatory approvals and permits for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals or permits, if we fail to obtain or comply with them, or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. We expect that costs we incur to comply with environmental regulations in the future may have a significant effect on our earnings and cash flows.

In November 2020, we set new ESG goals for the future related to GHG emissions reduction. Our ability to achieve these goals depends on many factors, including our ability to reduce emissions from our operations through modernization and innovation, reduce the emissions intensity of the electricity we buy, invest in renewables and low carbon energy and balance residual emissions through carbon offset credits. The cost associated with our GHG emissions reduction goals could be significant. There is also a risk that some or all of the expected benefits and opportunities of achieving the various GHG emissions reduction and energy transition goals may fail to materialize, may cost more to achieve or may not occur within the anticipated time periods. Similarly, there is a risk that emissions reduction technology – like battery storage or direct air capture – do not materialize as expected making it more difficult to reduce emissions. Failure to achieve our emissions targets could result in reputational harm, changing investor sentiment regarding investment in Enbridge or a negative impact on access to and cost of capital, including penalties associated with our sustainability-linked bond offerings.

Our operations are subject to operational regulation and other requirements, including compliance with easements and other land tenure documents, and failure to comply with applicable regulations and other requirements could have a negative impact on our reputation, business, operations or financial results.
Operational risks relate to compliance with applicable operational rules and regulations mandated by governments, applicable regulatory authorities, or other requirements that may be found in easements or other agreements that provide a legal basis for our operations, breaches of which could result in fines, penalties, awards of damages, operating restrictions (including shutdown of lines) and an overall increase in operating and compliance costs. We do not own all of the land on which our pipelines, facilities and other assets are located and we obtain the rights to construct and operate our pipelines and other assets from third parties or government entities. In addition, some of our pipelines, facilities and other assets cross Indigenous lands pursuant to rights-of-way or other land tenure interests. Our loss of these rights could have an adverse effect on our reputation, operations and financial results. Regulator scrutiny over our assets and operations has the potential to increase operating costs or limit future projects. Regulatory enforcement actions issued by regulators for non-compliant findings can increase operating costs and negatively impact reputation. Potential regulatory changes and legal challenges could have an impact on our future earnings from existing operations and the cost related to the construction of new projects. Regulators' future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which we operate. While we seek to mitigate operational regulation risk by actively monitoring and consulting on potential regulatory requirement changes with the respective regulators directly, or through industry associations, and by developing response plans to regulatory changes or enforcement actions, such mitigation efforts may be ineffective or insufficient. While we believe the safe and reliable operation of our assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators or other government officials to make unilateral decisions that could disrupt our operations or have an adverse financial impact on us.

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Our operations are subject to economic regulation and failure to secure regulatory approval for our proposed or existing commercial arrangements could have a negative impact on our business, operations or financial results.
Our liquids pipelines, gas transmission and gas distribution assets face economic regulation risk. Broadly defined, economic regulation risk is the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements or policies, including permits and regulatory approvals for both new and existing projects or agreements, upon which future and current operations are dependent. Our Mainline System, other liquids pipelines and gas transmission assets are subject to the actions of various regulators, including the CER and the FERC, with respect to the tariffs and tolls of those pipelines. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable permits and tariff structure or changes in interpretations of existing regulations by courts or regulators such as with respect to Mainline Contrating, could have an adverse effect on our revenues and earnings.

We could be subject to changes in our tax rates, the adoption of new US, Canadian or international tax legislation or exposure to additional tax liabilities.
We are subject to taxes in the US, Canada and numerous foreign jurisdictions. Due to economic and political conditions, tax rates in various jurisdictions may be subject to significant change. Our effective tax rates could be affected by changes in the mix of earnings in countries with differing statutory tax rates, changes in the valuation of deferred tax assets and liabilities, or changes in tax laws or their interpretation. In particular, we are anticipating interest deductibility rules to be tabled in Canada, possible new tax legislation to be passed in the US and a minimum tax rate to be introduced on a global basis for OECD countries. All of these measures could cause our effective tax rate to increase.

We are also subject to the examination of our tax returns and other tax matters by the US Internal Revenue Service, the Canada Revenue Agency and other tax authorities and governmental bodies. We regularly assess the likelihood of an adverse outcome resulting from these examinations to determine the adequacy of our provision for taxes. There can be no assurance as to the outcome of these examinations. If our effective tax rates were to increase, particularly in the US or Canada, or if the ultimate determination of our taxes owed is for an amount in excess of amounts previously accrued, our financial condition and operating results could be materially adversely affected.

We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could adversely affect our financial results.
We are subject to numerous legal proceedings. In recent years there has been an increase in climate and disclosure-related litigation against governments as well as companies involved in the energy industry. There is no assurance that we will not be impacted by such litigation. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could adversely affect our financial results or affect our reputation. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for a discussion of certain legal proceedings with recent developments.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

Descriptions of our properties and maps depicting the locations of our liquids and natural gas systems are included in Part 1. Item 1. Business.

In general, our systems are located on land owned by others and are operated under easements and rights-of-way, licenses, leases or permits that have been granted by private land-owners, First Nations, Native American Tribes, public authorities, railways or public utilities. Our liquids pipeline systems have pumping stations, tanks, terminals and certain other facilities that are located on land that is owned by us and/or used by us under easements, licenses, leases or permits. Additionally, our natural gas pipeline systems have natural gas compressor stations, of which the vast majority are located on land that is owned by us, with the remainder used by us under easements, leases or permits.

Titles to Enbridge owned properties or affiliate entities may be subject to encumbrances in some cases. We believe that none of these burdens should materially detract from the value of these properties or materially interfere with their use in the operation of our business.

ITEM 3. LEGAL PROCEEDINGS

We are involved in various legal and administrative proceedings and litigation arising in the ordinary course of business. The outcome of these matters is not predictable at this time. However, we believe that the ultimate resolution of these matters will not have a material adverse effect on our financial condition, results of operations or cash flows in future periods. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of certain legal proceedings with recent developments.

SEC regulations require the disclosure of any proceeding under environmental laws to which a governmental authority is a party unless the registrant reasonably believes it will not result in monetary sanctions over a certain threshold. Given the size of our operations, we have elected to use a threshold of US$1 million for the purposes of determining proceedings requiring disclosure.

The Minnesota Department of Natural Resources (DNR) issued an Administrative Penalty Order on September 16, 2021 due to an uncontrolled groundwater flow at Clearbrook. The groundwater flow was stopped in January 2022 after diligently implementing the steps required under the remedial action plan. We have also provided all required information to date. A contested case was not sought in this matter; instead, the penalty and mitigation amounts will be paid as directed for the Clearbrook site. A separate US$2.75 million escrow account is being established for any potential future monitoring and mitigation. In total, Enbridge will direct US$3.3 million to address this matter. With work complete at Clearbrook and a second site, Enbridge continues to work with the DNR towards a corrective action plan for the final location, including ongoing restoration, monitoring, and mitigation for all three sites.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.
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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Common Stock
Enbridge common stock is traded on the TSX and NYSE under the symbol “ENB.” As at February 4, 2022, there were 80,754 registered shareholders of record of Enbridge common stock. A substantially greater number of holders of Enbridge common stock are "street name" or beneficial holders, whose shares are held by banks, brokers and other financial institutions.

Securities Authorized for Issuance Under Equity Compensation Plans
The information required by this Item will be contained in our Form 10-K/A, which will be filed no later than 120 days after December 31, 2021.

Recent Sales of Unregistered Equity Securities
None.

Issuer Purchases of Equity Securities
None.

Total Shareholder Return
The following graph reflects the comparative changes in the value from January 1, 2017 through December 31, 2021 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the S&P/TSX Composite index, (3) the S&P 500 index, (4) our US peer group (comprising CNP, D, DTE, DUK, EPD, ET, KMI, MMP, NEE, NI, OKE, PAA, PCG, SO, SRE and WMB) and (5) our Canadian peer group (comprising CU, FTS, PPL and TRP). The amounts included in the table were calculated assuming the reinvestment of dividends at the time dividends were paid.

enb-20211231_g6.jpg

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 January 1,
2017
December 31,
 20172018201920202021
Enbridge Inc.100.00 91.20 83.64 108.32 91.84 119.50 
S&P/TSX Composite100.00 109.10 99.40 122.14 128.98 161.34 
S&P 500 Index100.00 121.83 116.49 153.17 181.35 233.41 
US Peers1
100.00 103.37 99.41 121.77 107.12 131.86 
Canadian Peers100.00 110.39 101.93 133.27 110.56 138.14 
1For 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]


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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with "Forward-Looking Information" and "Non-GAAP and Other Financial Measures", Part I. Item 1A. Risk Factors and our consolidated financial statements and the accompanying notes included in Part II. Item 8. Financial Statements and Supplementary Data of this Annual Report on Form 10-K.

This section of our Annual Report on Form 10-K discusses 2021 and 2020 items and year-over-year comparisons between 2021 and 2020. For discussion of 2019 items and year-over-year comparisons between 2020 and 2019, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2020.

RECENT DEVELOPMENTS

ACQUISITION OF MODA MIDSTREAM OPERATING, LLC

On October 12, 2021, we acquired Moda Midstream Operating, LLC (Moda) for $3.7 billion (US$3.0 billion) of cash plus potential contingent payments dependent on performance of the assets (the Acquisition). Moda owns and operates a vertically-integrated crude export system of pipeline and storage assets on the US Gulf Coast, including the EIEC located near Corpus Christi, Texas. EIEC, North America's largest crude export terminal, controls 15.6 million barrels of storage and 1.6 million barrels per day (mmbpd) of export capacity and volumes are underpinned by 925- thousand barrels per day (kbpd) of long-term take-or-pay vessel loading contracts and 15.3 million barrels of long-term storage contracts. The Acquisition aligns with and advances our US Gulf Coast export strategy and connectivity to low-cost and long-lived reserves in the Permian and Eagle Ford basins.

NORMAL COURSE ISSUER BID

On December 31, 2021, we announced that the Toronto Stock Exchange (TSX) had approved our normal course issuer bid (NCIB) to purchase, for cancellation, up to 31,062,331 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion, subject to certain restrictions on the number of common shares that may be purchased on a single day.

Purchases under the NCIB may be made through the facilities of the TSX, the New York Stock Exchange (NYSE) and other designated exchanges and alternative trading systems, commencing on January 5, 2022 and continuing until January 4, 2023, when the bid expires, or such earlier date on which Enbridge has either acquired the maximum number of common shares allowable under the NCIB or otherwise decide not to make any further repurchases under the NCIB. The maximum number of common shares that Enbridge may repurchase for cancellation represents approximately 1.53% of the 2,026,085,179 common shares issued and outstanding as at December 22, 2021.

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MAINLINE SYSTEM CONTRACTING

On December 19, 2019, we submitted an application to the Canada Energy Regulator (CER) to implement contracting on our Canadian Mainline System. On November 26, 2021, the CER denied the application on the basis that, among other things, contracting as proposed would result in a significant change to access the Canadian Mainline and potentially inequitable outcomes to some shippers and non-shippers without a compelling justification.

We are currently exploring with customers and other stakeholders alternatives that may include: a modified and extended Competitive toll Settlement (CTS), a new incentive rate-making agreement or a cost-of-service rate-making structure. Any negotiated settlement would require CER approval before implementation.

In accordance with the terms of the CTS, which expired on June 30, 2021, the tolls in place on June 30, 2021 will continue on an interim basis, subject to finalization and adjustment applicable to the interim period, if any.

GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS

Texas Eastern Transmission
Texas Eastern Transmission, LP (Texas Eastern) filed a rate case on July 30, 2021. On August 31, 2021 the Federal Energy Regulatory Commission (FERC) issued an order rejecting the July 30, 2021 filing in its entirety noting the proposed US federal income tax rate in the filing was not known and measurable (“August 2021 Order”). Additionally, the August 31, 2021 order directed Texas Eastern to show cause that its reservation charge crediting process is in accordance with FERC policy.

In response to the August 2021 Order, on September 30, 2021 Texas Eastern responded to the show cause directive and filed a new rate case using the current US federal income tax rate. On October 29, 2021, the FERC issued an order accepting and suspending tariff records, subject to refund, conditions, and establishing hearing procedures for the new rate case filed on September 30, 2021.

Texas Eastern also filed for rehearing of the August 2021 Order. On January 20, 2022 the FERC issued an “Order Addressing Arguments Raised On Rehearing And Setting Aside Prior Order, In Part” (“January 2022 Order”). The January 2022 Order set aside the August 2021 Order, and accepted and suspended Texas Eastern’s proposed rates from its initial rate case filing to be effective upon motion on February 1, 2022, subject to refund, conditions, and the outcome of hearing proceedings. In addition, the January 2022 Order directed Texas Eastern to remove its proposed income tax adjustment and include the actual tax rate in the computation of its rates when it files to motion the suspended rates into effect.

Finally, the FERC left to the discretion of the Chief Administrative Law Judge whether to consolidate the two rate case proceedings.

East Tennessee
East Tennessee Natural Gas, LLC (ETNG) filed a rate case in the second quarter of 2020 and an agreement in principle was reached with shippers in April 2021. A Stipulation and Agreement was filed on May 21, 2021, approved by the FERC on September 10, 2021 and was effective on November 1, 2021.

Maritimes & Northeast Pipeline
The US portion of Maritimes & Northeast Pipeline filed a rate case in the second quarter of 2020 and an agreement in principle was reached with shippers in December 2020. A Stipulation and Agreement was filed on February 17, 2021, approved by the FERC on April 30, 2021 and was effective on June 1, 2021. In December 2021, the CER approved interim rates for the Canadian portion of Maritimes & Northeast Pipeline effective January 1, 2022, which were based on the negotiated 2022 rates in the 2022-2023 settlement agreement and unanimously supported by shippers. A decision from the CER on the 2022-2023 settlement agreement is expected in the first quarter of 2022.

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Alliance Pipeline
The US portion of Alliance Pipeline filed a rate case in the second quarter of 2020 and an agreement in principle was reached with shippers in January 2021. A Stipulation and Agreement was filed on March 31, 2021, approved by the FERC on July 15, 2021 and was effective on September 1, 2021.

British Columbia (BC) Pipeline
The settlement agreement for our BC Pipeline system expired in December 2021. The CER has approved 2022 interim tolls for BC Pipeline and settlement agreement negotiations are ongoing, with an expected agreement to be reached in the first half of 2022.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

2021 Rate Application
Enbridge Gas Inc.'s (Enbridge Gas) rate applications are filed in two phases. As part of an Ontario Energy Board (OEB) Decision and Order issued in November 2020, Phase 1 of the application for 2021 rates (the 2021 Application), exclusive of 2021 capital investment funding requested through the incremental capital module (ICM) mechanism, was approved on an interim basis effective January 1, 2021. Through a subsequent OEB Rate Order issued in June 2021, Phase 2 of the 2021 Application, inclusive of funding for $124 million of requested 2021 ICM amounts, was approved effective July 1, 2021, and interim rates in effect for 2021 were made final. The 2021 Application, which represented the third year of a five-year term, was filed in accordance with the parameters of the Enbridge Gas OEB approved Price Cap Incentive Regulation (IR) rate setting mechanism.

2022 Rate Application
In June 2021, Enbridge Gas filed Phase 1 of the application with the OEB for the setting of rates for 2022 (the 2022 Application). The 2022 Application was filed in accordance with the parameters of the Enbridge Gas OEB approved Price Cap IR rate setting mechanism which represents the fourth year of a five-year term. In October 2021, the OEB approved a Phase 1 Settlement Proposal and Interim Rate Order effective January 1, 2022. Phase 2 of the 2022 Application addressing ICM funding requirements was filed in October 2021, with a decision from the OEB expected in the second quarter of 2022.

FINANCING UPDATE

We completed long-term debt issuances totaling US$3.9 billion and $3.2 billion during the year ended December 31, 2021, including an inaugural US$1.0 billion 12-year sustainability-linked senior notes issuance in June 2021 and an inaugural $1.1 billion Canadian 12-year sustainability-linked medium-term notes issuance in September 2021. We renewed approximately $8.0 billion of our five-year credit facilities, extending the maturity date out to July 2026. We also extended approximately $10.0 billion of our 364-day extendible credit facilities to July 2022, which includes a one-year term out provision to July 2023.

Our 2021 financing activities, in combination with the asset monetization activities noted below, provide significant liquidity that we expect will enable us to fund our current portfolio of capital projects without requiring access to the capital markets for the next 12 months should market access be restricted or pricing is unattractive. Refer to Liquidity and Capital Resources.

On January 19, 2022, we closed a $750 million private placement offering of non-call 10-year fixed-to-fixed subordinated notes which mature on January 19, 2082. The net proceeds from the offering will be used to redeem the Preference Shares, Series 17 at par on March 1, 2022.

On February 10, 2022 we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025.

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Credit Rating Action
On June 1, 2021, Moody's Investors Service (Moody's) upgraded the credit ratings of Enbridge Inc., including our senior unsecured and issuer ratings, to Baa1 from Baa2. Moody's also upgraded the credit ratings of our subsidiaries: Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Limited Partnership (EELP), Spectra Energy Partners, LP (SEP) and Texas Eastern. The outlooks of all five entities are stable.

ENERGY TRANSITION

Given the priority we are placing on low carbon investments and energy transition, we have established a dedicated New Energy Technologies team. This team will extend the capabilities we have built over the last 20 years of renewable investments and will establish priorities and co-ordinate strategy across our business units. The team will also develop new partnerships to enable access to new technology, complementary assets and skills.

During 2021, the Alberta Solar One and Heidlersburg solar self-power projects were placed into service. We also started the construction process on 10 additional solar self-power projects in Wisconsin, Illinois, Pennsylvania, Kentucky, Ohio and Minnesota, together capable of generating more than 97 megawatts (MW) MW of emissions-free electricity. These projects will provide clean power to our liquids and natural gas pipeline right-of-way and support scope 1 and 2 emission targets.

ASSET MONETIZATION

Éolien Maritime France SAS
On March 18, 2021, we sold 49% of an entity that holds our 50% interest in Éolien Maritime France SAS (EMF) to the Canada Pension Plan Investment Board (CPP Investments). CPP Investments will fund their 49% share of all ongoing future development capital. Through our investment in EMF, we own equity interests in three French offshore wind projects, including Saint-Nazaire (25.5%), Fécamp (17.9%) and Calvados (21.7%). The Calvados Offshore Wind Project reached a positive final investment decision in February 2021 and all three projects are now considered commercially secured and are under construction.

Noverco Inc.
On December 30, 2021, we sold our 38.9% non-operating minority ownership interest in Noverco Inc. (Noverco) to Trencap L.P. for $1.1 billion in cash.

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RESULTS OF OPERATIONS
Year ended December 31,
 202120202019
(millions of Canadian dollars, except per share amounts)   
Segment earnings before interest, income taxes and depreciation and amortization1
   
Liquids Pipelines7,897 7,683 7,681 
Gas Transmission and Midstream3,671 1,087 3,371 
Gas Distribution and Storage2,117 1,748 1,747 
Renewable Power Generation508 523 111 
Energy Services(313)(236)250 
Eliminations and Other356 (113)429 
Earnings before interest, income taxes and depreciation and amortization1
14,236 10,692 13,589 
Depreciation and amortization(3,852)(3,712)(3,391)
Interest expense(2,655)(2,790)(2,663)
Income tax expense(1,415)(774)(1,708)
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests(125)(53)(122)
Preference share dividends(373)(380)(383)
Earnings attributable to common shareholders5,816 2,983 5,322 
Earnings per common share2.87 1.48 2.64 
Diluted earnings per common share2.87 1.48 2.63 
1Non-GAAP financial measures.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Year ended December 31, 2021 compared with year ended December 31, 2020

Earnings Attributable to Common Shareholders increased by $2.2 billion due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
a non-cash, unrealized net gain of $53 million ($40 million after-tax) in 2021, compared with an unrealized net loss of $122 million ($92 million after-tax) in 2020 reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices;
an impairment loss of $111 million ($83 million after-tax) in 2021 to our investment in the PennEast pipeline project after a decision by project partners to cease development, compared to a combined impairment loss of $615 million ($452 million after-tax) in 2020 to our investments in Southeast Supply Header (SESH) and Steckman Ridge, LP (Steckman);
a gain of $303 million ($298 million after-tax) resulting from the sale of our investment in Noverco;
employee severance, transition and transformation costs of $147 million ($112 million after-tax) in 2021, compared to $339 million ($256 million after-tax) in 2020 primarily related to our voluntary workforce reduction program offered in the second quarter of 2020;
the absence in 2021 of a non-cash impairment to the carrying value of our investment in DCP Midstream, LLC (DCP Midstream) of $1.7 billion ($1.3 billion after-tax) and a $324 million loss ($244 million after-tax) resulting from our share of asset and goodwill impairments recognized by DCP Midstream, both recognized in 2020; and
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the absence in 2021 of a $159 million loss ($119 million after-tax) recorded in 2020 to reflect the Texas Eastern rate case settlement that re-established the Excess Accumulated Deferred Income Tax (EDIT) regulated liability that was previously eliminated in December 2018; partially offset by
a non-cash, unrealized derivative fair value net gain of $197 million ($150 million after-tax) in 2021, compared with a net gain of $856 million ($646 million after-tax) in 2020, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks.

The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on financial derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.

After taking into consideration the factors above, the remaining $657 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:
stronger contributions from our Liquids Pipelines segment due to increased volumes enabled by incremental Line 3 capacity placed into service in the fourth quarter of 2021 and a higher Mainline International Joint Tariff (IJT) Benchmark Toll, partially offset by the recognition of a provision against the interim Mainline IJT for barrels shipped between July 1, 2021 and December 31, 2021;
increased earnings from our Gas Distribution and Storage segment due to increased rates and customer base;
higher equity earnings from our Aux Sable and DCP Midstream joint ventures in our Gas Transmission and Midstream; and
lower interest expense for the first nine months of 2021 due to favourable interest rates on short-term borrowings, and the impact of a weaker US dollar currency that positively impacted the translation of interest payments on US dollar denominated debt.

The business factors above were partially offset by the following:
decreased earnings from our Energy Services segment due to the significant compression of location and quality differentials in certain markets, fewer storage opportunities due to market backwardation, adverse impacts from the major winter storm experienced across the US Midwest during February 2021 and fewer opportunities to achieve profitable transportation margins on facilities in which Energy Services holds capacity obligations;
the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average exchange rate in 2021 compared to the same period in 2020;
the absence in 2021 of the recognition of revenue in 2020 from a rate settlement on Texas Eastern, partially offset by increased revenue due to the absence of pressure restrictions that existed on the Texas Eastern system in 2020; and
higher depreciation expense on new assets placed into service throughout 2021, including the US L3R Program, placed into service early in the fourth quarter and the EIEC, acquired in mid-October.

REVENUES
We generate revenues from three primary sources: transportation and other services, gas distribution sales and commodity sales.

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Transportation and other services revenues of $16.2 billion, $16.2 billion and $16.6 billion for the years ended December 31, 2021, 2020 and 2019, respectively, were earned from our crude oil and natural gas pipeline transportation businesses and also include power generation revenues from our portfolio of renewable and power generation assets. For our transportation assets operating under market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator and, in most cost-of-service based arrangements, are reflective of our cost to provide the service plus a regulator-approved rate of return.

Gas distribution sales revenues of $4.0 billion, $3.7 billion and $4.2 billion for the years ended December 31, 2021, 2020 and 2019, respectively, were recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are primarily driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through to customers through rates and does not ultimately impact earnings due to its flow-through nature.

Commodity sales revenues of $26.9 billion, $19.3 billion and $29.3 billion for the years ended December 31, 2021, 2020 and 2019, respectively, were generated primarily through our Energy Services operations. Energy Services includes the contemporaneous purchase and sale of crude oil, natural gas, power and Natural Gas Liquids (NGLs) to generate a margin, which is typically a small fraction of gross revenue. While sales revenue generated from these operations are impacted by commodity prices, net margins and earnings are relatively insensitive to commodity prices and reflect activity levels which are driven by differences in commodity prices between locations, grades and points in time, rather than on absolute prices. Any residual commodity margin risk is closely monitored and managed. Revenues from these operations depend on activity levels, which vary from year-to-year depending on market conditions and commodity prices.

Our revenues also include changes in unrealized derivative fair value gains and losses related to foreign exchange and commodity price contracts used to manage exposures from movements in foreign exchange rates and commodity prices. The mark-to-market accounting creates volatility and impacts the comparability of revenues in the short-term, but we believe over the long-term, the economic hedging program supports reliable cash flows.

BUSINESS SEGMENTS

LIQUIDS PIPELINES
 202120202019
(millions of Canadian dollars)   
Earnings before interest, income taxes and depreciation and
amortization1
7,897 7,683 7,681 
1Non-GAAP financial measure.

Year ended December 31, 2021 compared with year ended December 31, 2020

EBITDA was negatively impacted by $335 million due to certain unusual, infrequent or other non-operating factors, primarily explained by a non-cash, unrealized gain of $120 million in 2021 compared with an unrealized gain of $545 million in 2020 reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks.

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The factor above was partially offset by the following:
a property tax settlement receipt of $57 million in 2021 related to the resolution of Minnesota property tax appeals for the tax years 2012 through 2018; and
the absence in 2021 of $30 million of asset impairment losses recognized in 2020.

After taking into consideration the factors above, the remaining $549 million increase is primarily explained by the following factors:
higher Mainline system ex-Gretna average throughput of 2.8 million barrels per day (mmbpd) in 2021 as compared to 2.6 mmbpd in 2020 driven by the rebounding demand for crude oil and related products as economies continue to recover from the impacts of the COVID-19 pandemic;
incremental L3R capacity that came into service October 2021 further supporting demand growth and the implementation of full L3R surcharge of US$0.93 per barrel beginning October 2021 compared to the Canadian L3R program US$0.20 per barrel;
a higher average IJT Benchmark Toll on our Mainline System of US$4.27 in 2021, compared with US$4.24 in 2020;
a higher foreign exchange hedge rate used to lock-in US dollar denominated Canadian Mainline revenue; and
higher equity income from our investment in the Seaway Crude Pipeline System driven by increased volumes.

The positive business factors above were partially offset by the following:
the recognition of a provision in the fourth quarter against the interim Mainline IJT for barrels shipped between July 1, 2021 and December 31, 2021; and
the net unfavorable effect of translating US dollar EBITDA to Canadian dollars at a lower average exchange rate in 2021 versus 2020.

GAS TRANSMISSION AND MIDSTREAM
 202120202019
(millions of Canadian dollars)   
Earnings before interest, income taxes and depreciation and amortization1
3,671 1,087 3,371 
1Non-GAAP financial measure.

Year ended December 31, 2021 compared with year ended December 31, 2020

EBITDA was positively impacted by $2.6 billion due to certain unusual, infrequent or other non-operating factors primarily explained by the following:
an impairment loss of $111 million in 2021 to our investment in the PennEast pipeline project after a decision by project partners to cease development, compared to a combined impairment loss of $615 million in 2020 to our investments in SESH and Steckman;
the absence in 2021 of a $1.7 billion non-cash impairment to the carrying value of our investment in DCP Midstream and a $324 million loss resulting from our share of asset and goodwill impairments recognized by DCP Midstream, both recognized in 2020;
the absence in 2021 of a $159 million loss recorded in 2020 to reflect the Texas Eastern rate case settlement that re-established the EDIT regulated liability that was previously eliminated in December 2018; partially offset by
a negative impact in equity earnings of $44 million in 2021, compared with a positive impact of $22 million in 2020 relating to changes in the mark-to-market value of derivative financial instruments within our equity method investee, DCP Midstream.

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After taking into consideration the factors above, we saw a $45 million decrease to EBITDA that is primarily explained by the following business factors:
the net unfavorable effect of translating US dollar EBITDA at a lower Canadian to US dollar average exchange rate in 2021, compared to the same period in 2020; and
the absence in 2021 of the recognition of revenue in 2020 that related to the settlement of interim rates collected from shippers on Texas Eastern, retroactive to June 1, 2019.

The factors above were partially offset by the following positive factors:
higher commodity prices benefiting equity earnings from our Aux Sable and DCP Midstream joint ventures;
increased revenue due to the absence of pressure restrictions that existed on the Texas Eastern system in 2020; and
a full year of contributions from the Atlantic Bridge Phase III project after it commenced service in January of 2021.

GAS DISTRIBUTION AND STORAGE
 202120202019
(millions of Canadian dollars)   
Earnings before interest, income taxes and depreciation and amortization1
2,117 1,748 1,747 
1Non-GAAP financial measure.

Year ended December 31, 2021 compared with year ended December 31, 2020

EBITDA was positively impacted by $338 million due to certain unusual, infrequent or other non-operating factors primarily explained by the following:
a gain of $303 million resulting from the sale of our investment in Noverco; and
a non-cash, unrealized gain of $14 million in 2021, compared with a loss of $10 million in 2020, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risks.

After taking into consideration the positive factors above, the remaining $31 million increase is primarily explained by the following significant business factors:
higher distribution charges resulting from increases in rates and customer base; and
higher storage revenue, mainly relating to storage optimization activities.

The positive business factors above were partially offset by the following factors:
higher operating and administrative costs largely related to operational, pipeline integrity and safety costs; and
when compared with the normal weather forecast embedded in rates, weather was warmer in both 2021 and 2020, negatively impacting EBITDA in both years. Warmer than normal weather in 2021 negatively impacted 2021 EBITDA by approximately $55 million, while the warmer than normal weather in 2020 negatively impacted 2020 EBITDA by approximately $33 million.

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RENEWABLE POWER GENERATION

 202120202019
(millions of Canadian dollars)   
Earnings before interest, income taxes and depreciation and amortization1
508 523 111 
1Non-GAAP financial measure.

Year ended December 31, 2021 compared with year ended December 31, 2020

EBITDA was negatively impacted by $15 million primarily explained by the following significant business factors:
weaker wind resources at Canadian and United States wind facilities and the effects from the Texas winter storm in February 2021; and
the absence in 2021 of reimbursements received in 2020 at certain Canadian wind facilities resulting from a change in operator; partially offset by
the sale of a 49% interest of an entity that holds our 50% interest in EMF.

ENERGY SERVICES
 202120202019
(millions of Canadian dollars)   
Earnings/(loss) before interest, income taxes and depreciation and amortization1
(313)(236)250 
1Non-GAAP financial measure.

EBITDA from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

Year ended December 31, 2021 compared with year ended December 31, 2020

EBITDA was positively impacted by $164 million due to certain unusual, infrequent or other non-operating factors, primarily explained by a non-cash, unrealized net gain of $53 million in 2021, compared with a loss of $122 million in 2020, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices.

After taking into consideration the positive factors above, the remaining $241 million decrease is primarily explained by the following significant business factors:
significant compression of location and quality differentials in certain markets;
limited storage opportunities in 2021 due to market backwardation compared to favorable storage opportunities in 2020;
fewer opportunities to achieve profitable transportation margins on facilities in which Energy Services holds capacity obligations; and
adverse impacts from the major winter storm experienced across the US Midwest during February 2021.

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ELIMINATIONS AND OTHER
 202120202019
(millions of Canadian dollars)   
Earnings/(loss) before interest, income taxes and depreciation and amortization1
356 (113)429 
1Non-GAAP financial measure.

Eliminations and Other includes operating and administrative costs which are not allocated to business segments and the impact of foreign exchange hedge settlements. Eliminations and Other also includes the impact of new business development activities and corporate investments.

Year ended December 31, 2021 compared with year ended December 31, 2020

EBITDA was positively impacted by $24 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
employee severance, transition and transformation costs of $87 million in 2021 compared with $279 million in 2020 primarily related to our voluntary workforce reduction program offered in the second quarter of 2020;
the absence in 2021 of a non-cash loss of $74 million in 2020 relating to the recognition of a corporate guarantee obligation; and
the absence in 2021 of a loss of $43 million in 2020 relating to the write-down of certain investments in emerging energy and other technologies; partially offset by
a non-cash, unrealized gain of $55 million in 2021 compared with a gain of $318 million in 2020 reflecting net fair value gains and losses arising from the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk.

After taking into consideration the factors above, the remaining $445 million increase is primarily explained by realized gains related to settlements under our enterprise-wide foreign exchange risk management program which substantially offset the foreign currency exposures realized within our business segments’ results.

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GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS
The following table summarizes the status of our commercially secured projects, organized by business segment:
Enbridge's Ownership Interest
Estimated
Capital
Cost1
Expenditures
to Date
2
Status2
Expected
In-Service
Date
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
1.US Line 3 Replacement Program100 %US$4.0 billionUS$4.1 billionCompleteIn-service
2.Southern Access Expansion100 %US$0.5 billionUS$0.5 billionCompleteIn-service
3.Other - US100 %US$0.1 billionUS$0.1 billionCompleteIn-service
GAS TRANSMISSION AND MIDSTREAM
4.T-South Reliability & Expansion Program100 %$1.0 billion$0.9 billionCompleteIn-service
5.Spruce Ridge Project100 %$0.4 billion$0.4 billionCompleteIn-service
6.Texas Eastern Modernization100 %US$0.4 billionNo significant expenditures to datePre-construction2024 - 2026
7.Appalachia to Market II100 %US$0.1 billionNo significant expenditures to datePre-construction2025
8.
Other - US3
VariousUS$0.6 billionUS$0.4 billionVarious stages2021 - 2023
GAS DISTRIBUTION AND STORAGE
9.
System Enhancement Projects4
100 %$0.4 billion$0.1 billionVarious stages2021 - 2023
10.Storage Enhancements100 %$0.1 billionNo significant expenditures to dateUnder construction2H - 2022
11.
Natural Gas Expansion Program5
100 %$0.1 billionNo significant expenditures to datePre-construction2022 - 2027
RENEWABLE POWER GENERATION
12.East-West Tie Line25.0 %$0.2 billion$0.2 billionUnder construction1H - 2022
13.
Solar Self-Power Projects6
100 %US$0.2 billionNo significant expenditures to datePre-construction2022 - 2023
14.
Saint-Nazaire France Offshore Wind Project7
25.5 %$0.9 billion$0.5 billionUnder construction2H - 2022
(€0.6 billion)(€0.3 billion)
15.
Provence Grand Large Floating Offshore Wind Project8
25.0 %$0.1 billionNo significant expenditures to datePre-construction2023
(€0.1 billion)
16.
Fécamp Offshore Wind Project9
17.9 %$0.7 billion$0.3 billionUnder construction2023
(€0.5 billion)(€0.2 billion)
17.
Calvados Offshore Wind Project9
21.7 %$0.9 billion$0.1 billionPre-construction2024
(€0.6 billion)(€0.1 billion)
1These 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.
2Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2021.
3Includes the US$0.1 billion Texas Eastern Middlesex Extension placed into service in September of 2021 and the US$0.1 billion Cameron Extension Project placed into service in November of 2021.
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4Includes the $0.1 billion London Line Replacement Project placed into service in December of 2021. Total estimated capital cost consists of site restoration work expected to be completed in 2022.
5Represents Phase 2 of the Natural Gas Expansion Program (the Program) and the estimated capital cost is presented net of the maximum funding assistance we expect to receive from the Government of Ontario. The expected in-service dates represent the expected completion dates of the leave to construct requirements.
6Self-Power Projects consists of solar self-power projects along our liquids and gas transmission systems. All 10 projects will be located at existing pump and/or compressor stations.
7Reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first quarter of 2021. Our equity contribution is $0.15 billion, with the remainder of the project financed through non-recourse project level debt.
8Reflects the sale of 50% of an entity that holds our 50% interest in Provence Grand Large to CPP Investments. Our equity contribution is $0.05 billion, with the remainder of the project financed through non-recourse project level debt for each project.
9Each project reflects the sale of 49% of an entity that holds our 50% interest in EMF to CPP Investments that closed in the first quarter of 2021. Our equity contribution is $0.1 billion, with the remainder of the project financed through non-recourse project level debt.

Risks related to the development and completion of growth projects are described under Part I. Item 1A.Risk Factors.

LIQUIDS PIPELINES

The following commercially secured growth projects were placed into service in 2021:

United States Line 3 Replacement Program – replacement of the existing Line 3 crude oil pipeline between Neche, North Dakota and Superior, Wisconsin is now complete and in-service. The US L3R Program supports the safety and operational reliability of the Mainline System, enhances system flexibility and allows us to optimize throughput on the mainline. The US L3R Program restored the original capacity of 760 kbpd and brought the total Mainline System operating capacity to approximately 3.1 mmbpd.

Southern Access Expansion – expansion of our existing Southern Access crude oil pipeline from 996 kbpd to approximately 1,200 kbpd.

GAS TRANSMISSION AND MIDSTREAM

The following commercially secured growth projects were placed into service in 2021:

Atlantic Bridge Phase III – an expansion of the Algonquin natural gas transmission systems which transports 133 million cubic feet per day (mmcf/d) of natural gas to the New England region. The third and final phase of Atlantic Bridge fully commenced service in January 2021 with the Weymouth compressor station being brought online.

T-South Reliability & Expansion Program – a natural gas pipeline expansion of Westcoast's BC Pipeline in southern BC that provides improved compressor reliability and additional capacity of approximately 190 mmcf/d into the Huntington/Sumas market at the US/Canada border.

Spruce Ridge Project – a natural gas pipeline expansion of Westcoast's BC Pipeline in northern BC. The project provides additional capacity of up to 402 mmcf/d.

The following commercially secured growth projects are currently in pre-construction stages:

Texas Eastern Modernization Phase II – this program is the modernization of compression facilities in Pennsylvania and New Jersey to increase safety and reliability and reduce associated greenhouse gas emissions at multiple sites on our Texas Eastern system. The program will be completed in stages over a period of years beginning in 2024.

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Appalachia to Market II - the expansion is designed to deliver 55 MDth per day on the Texas Eastern pipeline from the Appalachia supply basin in Southwest Pennsylvania to existing local distribution company customers in New Jersey beginning in late 2025. The project is a brown-field expansion and upgrade of existing Texas Eastern facilities in Pennsylvania.

GAS DISTRIBUTION AND STORAGE

The following commercially secured growth project was placed into service in 2021:

System Enhancement Projects – The London Line Replacement Project replaced two existing pipelines known collectively as the London Line and included the construction of approximately 90.5- kilometers of natural gas pipeline and ancillary facilities in southern Ontario.

The following commercially secured growth projects are currently in various stages of construction:

System Enhancement Project – The Lake Shore Kipling Oshawa Loop (KOL) Replacement Project is a replacement of approximately 4.5-kilometers of natural gas pipeline and ancillary facilities of the Cherry to Bathurst segment of the KOL along Lake Shore Boulevard in the City of Toronto. The St. Laurent Ottawa North Replacement Project is a replacement of approximately 16-kilometers of natural gas pipeline in the City of Ottawa. The first two phases of this project have already been completed. Phases 3 and 4 represent approximately 11.4-kilometers of pipeline.

Storage Enhancements – Storage Enhancements are part of a larger delta pressuring project to increase deliverability and storage capacity at Enbridge Gas' storage facilities. The additional deliverability and storage capacity will be sold as part of Enbridge Gas' unregulated storage portfolio.

Natural Gas Expansion Program – The Program was created under the Access to Natural Gas Act, 2018 to help expand access to natural gas to areas of Ontario that currently do not have access to the natural gas distribution system. Under Phase 2 of the Program, we will be provided up to $214 million in funding assistance to deliver 25 community expansion and two economic development projects throughout Ontario.

RENEWABLE POWER GENERATION

The following commercially secured growth projects are currently in various stages of construction:

East-West Tie Line – a transmission project that will parallel an existing double-circuit, 230 kilovolt transmission line that connects the Wawa Transformer Station to the Lakehead Transformer Station near Thunder Bay, Ontario, including a connection midway in Marathon, Ontario.

Solar Self-Power Projects – 10 solar self-power projects under development in Wisconsin, Illinois, Pennsylvania, Kentucky, Ohio and Minnesota, with a combined estimate of 97 MW of emissions-free generating capacity. These projects will provide clean power directly to our liquids and natural gas pipeline rights-of-way.

Saint-Nazaire France Offshore Wind Project – a wind project located off the west coast of France that is expected to generate approximately 480-MW. Project revenues are backed by a 20-year fixed price power purchase agreement (PPA) with added power production protection.

Provence Grand Large Floating Offshore Wind Project – a floating offshore wind facility off the southern coast of France that secured funding in 2021 and continues to prepare onshore construction and is expected to generate approximately 24-MW. Project revenues are underpinned by a 20-year fixed price PPA.

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Fécamp Offshore Wind Project an offshore wind project located off the northwest coast of France and is expected to generate approximately 500-MW. Project revenues are underpinned by a 20-year fixed price PPA.

Calvados Offshore Wind Project an offshore wind project located off the northwest coast of France that is expected to generate approximately 448-MW. Project revenues are underpinned by a 20-year fixed price power purchase agreement.

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT
The following projects have been announced by us, but have not yet met our criteria to be classified as commercially secured:

LIQUIDS PIPELINES

Sea Port Oil Terminal Project – the Sea Port Oil Terminal (SPOT) project consists of onshore and offshore facilities, including a fixed platform located approximately 30 miles off the coast of Brazoria County, Texas. SPOT is designed to load very large crude carriers at rates of approximately 85,000 barrels per hour, or up to approximately 2 million bpd. Along with Enterprise Products Partners, L.P., we announced our intent to jointly develop and market SPOT, and we will work to finalize an equity participation agreement. The agreement will allow us to purchase an ownership interest in SPOT, subject to SPOT receiving a deep-water port license.

Enbridge Houston Oil Terminal – the terminal is expected to have an ultimate capability of up to 15 million barrels of storage, access to crude oil from all major North American production basins and will be fully integrated with the Seaway Crude Pipeline System to allow for access to Houston-area refineries, existing export facilities, the SPOT project and other facilities in the future.

GAS TRANSMISSION AND MIDSTREAM

Rio Bravo Pipeline – the Rio Bravo Pipeline is designed to transport up to 4.5 billion cubic feet per day (bcf/d) of natural gas from the Agua Dulce supply area to NextDecade Corporation's (NextDecade) Rio Grande liquefied natural gas (LNG) export facility in the Port of Brownsville, Texas. We have executed a precedent agreement with NextDecade under which we will provide firm transportation capacity on the Rio Bravo Pipeline to NextDecade's Rio Grande LNG export facility for a term of at least 20 years. Construction of the pipeline will be subject to the Rio Grande LNG export facility reaching a final investment decision.

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Ridgeline Expansion Project Opportunity We are working on a potential expansion of the ETNG system which would provide additional natural gas for the Tennessee Valley Authority (TVA) to support the replacement of an existing coal-fired power plant as it continues to transition its generation mix towards lower-carbon fuels. The TVA environmental review scoping process has begun for this proposed plant; TVA published a Notice of Intent on the Federal Register on June 15, 2021 to initiate their review process. Several options to replace the retiring coal-fired generation would be assessed in TVA’s Environmental Impact Statement (EIS). Should the onsite natural gas option of building a combined cycle plant be selected through TVA’s review, we would deliver on the required expansion of the East Tennessee system. ETNG’s proposed project would consist of the installation of additional pipeline primarily along the ETNG system, the installation of one electric-powered compressor station and solar facilities behind the meter, as well as other design features all contributing to minimizing greenhouse gas emissions. Should TVA’s environmental assessment determine that the natural gas solution of building an onsite combined cycle plant is the optimal supply source, and pending the approval and receipt of all necessary permits, construction of the pipeline would begin in 2025 with a target in-service date of fall 2026.

Valley Crossing Expansion Project On January 10, 2022, we executed a precedent agreement with Texas LNG Brownsville LLC (Texas LNG) under which, via an expansion of our Valley Crossing Pipeline, we will provide 0.72 bcf/d firm transportation capacity to Texas LNG’s proposed LNG liquefaction and export facility in the Port of Brownsville, Texas for a term of at least 20 years. Expansion of the pipeline will be subject to Texas LNG’s export facility reaching a final investment decision.

Texas Eastern Venice Extension Project - a reversal and expansion of Texas Eastern’s Line 40 from its existing New Roads compressor station to a new delivery point with the proposed Gator Express pipeline just south of Texas Eastern’s Larose compressor station. The project is expected to deliver 1.26 bcf/d of feed gas to Venture Global’s proposed Plaquemines LNG export facility located in Plaquemine Parish, Louisiana. The expansion will be subject to the Plaquemines LNG export facility reaching a final investment decision.

We also have a portfolio of additional projects under development that have not yet progressed to the point of securement.

LIQUIDITY AND CAPITAL RESOURCES

The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control including, but not limited to, financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to ensure we maintain sufficient liquidity to meet routine operating and future capital requirements. In the near term, we generally expect to utilize cash from operations together with commercial paper issuance and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preference share dividends. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.

Material contractual obligations arising in the normal course of business primarily consist of long-term contracts, annual debt maturities and related interest obligations, rights-of-way and leases. See Part II. Item 8. Financial Statements and Supplementary data - Note 18 - Debt and Note 27 - Leases for amounts outstanding at December 31, 2021, related to debt and leases.

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Long-term contracts are contracts that we have signed for the purchase of services, pipe and other materials totaling $5.9 billion which are expected to be paid over the next five years. Long-term contracts also consists of the following purchase obligations: gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments.

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives. Our current financing plan does not include any issuances of additional common equity. On January 19, 2022, we closed a $750 million private placement offering of non-call 10-year fixed-to-fixed subordinated notes which mature on January 19, 2082. The net proceeds from the offering will be used to redeem the Preference Shares, Series 17 at par on March 1, 2022.

CAPITAL MARKET ACCESS
We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive. In accordance with our funding plan, we completed the following long-term debt issuances totaling US$3.9 billion and $3.2 billion in 2021:

EntityIssuance DateType of IssuanceAmount
(in millions of Canadian dollars, unless stated otherwise)
Enbridge Inc.February 2021Floating rate senior-notesUS$500
Enbridge Inc.June 2021Sustainability-linked senior notesUS$1,000
Enbridge Inc.June, October 2021Senior notesUS$2,000
Enbridge Inc.September 2021Medium-term notes$1,100
Enbridge Inc.September 2021Sustainability-linked medium-term notes$400
Enbridge Gas Inc.September 2021Medium-term notes$900
Enbridge Pipelines Inc.May 2021Medium-term notes$800
Spectra Energy Partners, LP1
September 2021Senior notesUS$400
1Issued through Texas Eastern, a wholly-owned operating subsidiary of SEP.

Credit Facilities, Ratings and Liquidity
To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities at December 31, 2021:
Maturity1
Total Facilities
Draws2
Available
(millions of Canadian dollars)    
Enbridge Inc.2022-20269,137 7,837 1,300 
Enbridge (U.S.) Inc.2023-20266,948 4,845 2,103 
Enbridge Pipelines Inc.20233,000 667 2,333 
Enbridge Gas Inc.20232,000 1,515 485 
Total committed credit facilities 21,085 14,864 6,221 
1Maturity date is inclusive of the one-year term out option for certain credit facilities.
2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

On February 10, 2021, Enbridge Inc. entered into a three year, revolving, extendible, sustainability-linked credit facility for $1.0 billion with a syndicate of lenders and concurrently terminated our one year, revolving, syndicated credit facility for $3.0 billion.

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On July 22 and 23, 2021, we renewed approximately $8.0 billion of our five-year credit facilities, extending the maturity date out to July 2026. We also extended approximately $10.0 billion of our 364-day extendible credit facilities to July 2022, which includes a one-year term out provision to July 2023.

On February 10, 2022 we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025.

In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $854 million was unutilized as at December 31, 2021. As at December 31, 2020, we had $849 million of uncommitted demand letter of credit facilities, of which $533 million was unutilized.

As at December 31, 2021, our net available liquidity totaled $6.5 billion (2020 - $12.7 billion), consisting of available credit facilities of $6.2 billion (2020 - $12.3 billion) and unrestricted Cash and cash equivalents of $286 million (2020 - $452 million) as reported in the Consolidated Statements of Financial Position.

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions, whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2021, we were in compliance with all debt covenants and expect to continue to comply with such covenants.
Cash flow growth, proceeds from non-core asset dispositions, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA.
On June 1, 2021, Moody's upgraded the credit ratings of Enbridge Inc., including our senior unsecured and issuer ratings, to Baa1 from Baa2. Moody's also upgraded the credit ratings of our subsidiaries: EEP, EELP, SEP and Texas Eastern. The outlooks of all five entities are stable.

There are no material restrictions on our cash. Total Restricted cash of $34 million, as reported on the Consolidated Statements of Financial Position, primarily includes cash collateral and future pipeline abandonment costs collected and held in trust. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative use by us.

Excluding current maturities of long-term debt, as at December 31, 2021 and 2020, we had a negative working capital position of $3.1 billion and $3.7 billion, respectively. In both periods, the major contributing factor to the negative working capital position was the current liabilities associated with our growth capital program.
To address this negative working capital position, we maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due.
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SOURCES AND USES OF CASH

Year ended December 31,202120202019
(millions of Canadian dollars)   
Operating activities9,256 9,781 9,398 
Investing activities(10,657)(5,177)(4,658)
Financing activities1,236 (4,770)(4,745)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash(5)(20)44 
Net increase/(decrease) in cash and cash equivalents and restricted cash(170)(186)39 
Significant sources and uses of cash for the years ended December 31, 2021 and 2020 are summarized below:

Operating Activities
Typically, the primary factors impacting cash flow from operating activities year-over-year include changes in our operating assets and liabilities in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments, as well as timing of cash receipts and payments generally. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 28. Changes in Operating Assets and Liabilities. Cash provided by operating activities is also impacted by changes in earnings and certain unusual, infrequent and other non-operating factors, as discussed under Results of Operations.

Investing Activities
We continue with the execution of our growth capital program which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.

A summary of additions to DCF. DCFproperty, plant and equipment for the years ended December 31, 2021, 2020 and 2019 is set out below:

Year ended December 31,202120202019
(millions of Canadian dollars)   
Liquids Pipelines4,051 2,032 2,548 
Gas Transmission and Midstream2,353 2,066 1,695 
Gas Distribution and Storage1,343 1,134 1,100 
Renewable Power Generation16 81 23 
Energy Services1 
Eliminations and Other54 90 124 
Total capital expenditures7,818 5,405 5,492 

2021
The increase in cash used in investing activities primarily resulted from the following factors:
Our acquisition of Moda on October 12, 2021 and higher capital expenditures related to the completion of the US L3R Program, partially offset by higher proceeds received from dispositions in 2021 compared with 2020 due to the sale of our interest in Noverco on December 30, 2021.

2020
The increase in cash used in investing activities primarily resulted from the following factors:
Lower proceeds from asset dispositions in 2020 compared with 2019, primarily due to the sale of the federally regulated portion of our Canadian natural gas gathering and processing businesses assets on December 31, 2019.
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The factor above was partially offset by lower contributions to the Gray Oak Holdings LLC equity investment in 2020, higher return of capital primarily from equity investments in Seaway Crude Holdings LLC, MarEn Bakken Company LLC, Gray Oak Holdings LLC and Enbridge Renewable Infrastructure Investments S.a.r.l., and lower net cash invested in affiliate loans in 2020 compared with 2019.

Financing Activities
Cash provided by and used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances and share redemptions. Cash from financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests.

2021
The increase in cash provided by financing activities primarily resulted from the following factors:
Increased issuances of long-term debt, commercial paper and credit facility draws and short-term borrowings, along with lower repayments of long-term debt in 2021 compared to 2020.
The factors above were partially offset by the redemption of Westcoast Energy Inc.'s (Westcoast) preferred shares in 2021 and increased common share dividend payments primarily due to the increase in our common share dividend rate.

2020
Cash used in financing activities in 2020 was consistent with 2019 due to the following factors:
Increased commercial paper and credit facility draws, increased short-term borrowings and lower repayments of long-term debt in 2020 compared with 2019, partially offset by lower issuances of long-term debt.
•    The absence in 2020 of the redemption of Westcoast's preferred shares in 2019.
•    The above factors were partially offset by increased common share dividend payments primarily due to the increase in our common share dividend rate.

OFF-BALANCE SHEET ARRANGEMENTS
We enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Part II. Item 8. Financial Statements and Supplementary Data - Note 31 Guarantees for further discussion of guarantee arrangements.

Most of the guarantee arrangements that we enter into enhance the credit standings of certain subsidiaries, non-consolidated entities or less than 100%-owned entities, enabling them to conduct business. As such, these guarantee arrangements involve elements of performance and credit risk which are not included on our Consolidated Statements of Financial Position. The possibility of us having to honor our contingencies is largely dependent upon the future operations of our subsidiaries, investees and other third parties, or the occurrence of certain future events. Issuance of these guarantee arrangements is not required for the majority of our operations.

We do not have material off-balance sheet financing entities or structures, except for guarantee arrangements and financings entered into by our equity investments. For additional information on these commitments, see Part II. Item 8. Financial Statements and Supplementary Data -Note 30 Commitments and Contingencies and Note 31 Guarantees.

We do not have material off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources.

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Preference Share Issuances
Since July 2011, we have issued 315 million preference shares for gross proceeds of approximately $7.9 billion with the following characteristics:
Gross ProceedsDividend Rate
Dividend1
Per Share
Base
Redemption
Value2
Redemption
and Conversion
Option Date2,3
Right to
Convert
Into3,4
(Canadian dollars, unless otherwise stated)    
Series A$125 million5.50 %$1.37500$25— — 
Series B$457 million3.42 %$0.85360$25June 1, 2022Series C
Series C5
$43 million3-month treasury bill plus 2.40%— $25June 1, 2022Series B
Series D$450 million4.46 %$1.11500$25March 1, 2023Series E
Series F$500 million4.69 %$1.17224$25June 1, 2023Series G
Series H$350 million4.38 %$1.09400$25September 1, 2023Series I
Series JUS$200 million4.89 %US$1.22160US$25June 1, 2022Series K
Series LUS$400 million4.96 %US$1.23972US$25September 1, 2022Series M
Series N$450 million5.09 %$1.27152$25December 1, 2023Series O
Series P$400 million4.38 %$1.09476$25March 1, 2024Series Q
Series R$400 million4.07 %$1.01825$25June 1, 2024Series S
Series 1US$400 million5.95 %US$1.48728US$25June 1, 2023Series 2
Series 3$600 million3.74 %$0.93425$25September 1, 2024Series 4
Series 5US$200 million5.38 %US$1.34383US$25March 1, 2024Series 6
Series 7$250 million4.45 %$1.11224$25March 1, 2024Series 8
Series 9$275 million4.10 %$1.02424$25December 1, 2024Series 10
Series 11$500 million3.94 %$0.98452$25March 1, 2025Series 12
Series 13$350 million3.04 %$0.76076$25June 1, 2025Series 14
Series 15$275 million2.98 %$0.74576$25September 1, 2025Series 16
Series 17$750 million5.15 %$1.28750$25March 1, 2022Series 18
Series 19$500 million4.90 %$1.22500$25March 1, 2023Series 20
1The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this feature.
2Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.
3The 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.
4With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in a year) x three-month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in a year) x three-month US Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6).
5The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.15501 from $0.15349 on March 1, 2021, was increased to $0.15753 from $0.15501 on June 1, 2021, was increased to $0.16081 from $0.15753 on September 1, 2021 and was decreased to $0.15719 from $0.16081 on December 1, 2021, due to reset on a quarterly basis following the issuance thereof.

PREFERENCE SHARE REDEMPTION
We intend to exercise our right to redeem all of our outstanding cumulative redeemable minimum rate reset preference shares, Series 17, on March 1, 2022 at a price of $25 per Series 17 share, together with all accrued and unpaid dividends, if any.

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Dividends
We have paid common share dividends in every year since we became a publicly traded company in 1953. In December 2021, we announced a 3% increase in our quarterly dividend to $0.86 per common share, or $3.44 annualized, effective with the dividend payable on March 1, 2022, thereby making a dividend increase for 27 straight years.

For the years ended December 31, 2021 and 2020, total dividends paid were $6.8 billion and $6.6 billion, respectively, all of which were paid in cash and reflected in financing activities.

On December 6, 2021, our Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2022 to shareholders of record on February 15, 2022.
Dividend per share
Common Shares1
$0.86000 
Preference Shares, Series A$0.34375 
Preference Shares, Series B$0.21340 
Preference Shares, Series C2
$0.15719 
Preference Shares, Series D$0.27875 
Preference Shares, Series F$0.29306 
Preference Shares, Series H$0.27350 
Preference Shares, Series JUS$0.30540 
Preference Shares, Series LUS$0.30993 
Preference Shares, Series N$0.31788 
Preference Shares, Series P$0.27369 
Preference Shares, Series R$0.25456 
Preference Shares, Series 1US$0.37182 
Preference Shares, Series 3$0.23356 
Preference Shares, Series 5US$0.33596 
Preference Shares, Series 7$0.27806 
Preference Shares, Series 9$0.25606 
Preference Shares, Series 11$0.24613 
Preference Shares, Series 13$0.19019 
Preference Shares, Series 15$0.18644 
Preference Shares, Series 17$0.32188 
Preference Shares, Series 19$0.30625 
1    The quarterly dividend per common share was increased 3% to $0.86 from $0.835, effective March 1, 2022.
2    The quarterly dividend per share paid on Series C was increased to $0.15501 from $0.15349 on March 1, 2021, was increased to $0.15753 from $0.15501 on June 1, 2021, was increased to $0.16081 from $0.15753 on September 1, 2021 and was decreased to $0.15719 from $0.16081 on December 1, 2021, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.

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SUMMARIZED FINANCIAL INFORMATION

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, SEP and EEP (the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they fully and unconditionally guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. The Partnerships have also entered into supplemental indentures with Enbridge pursuant to which the Partnerships have issued full and unconditional guarantees, on a senior unsecured basis, of senior notes issued by Enbridge subsequent to January 22, 2019. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes.

Consenting SEP notes and EEP notes under Guarantee

SEP Notes1
EEP Notes2
4.750% Senior Notes due 20245.875% Notes due 2025
3.500% Senior Notes due 20255.950% Notes due 2033
3.375% Senior Notes due 20266.300% Notes due 2034
5.950% Senior Notes due 20437.500% Notes due 2038
4.500% Senior Notes due 20455.500% Notes due 2040
7.375% Notes due 2045
1As at December 31, 2021, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.
2As at December 31, 2021, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

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Enbridge Notes under Guarantees
US Dollar Denominated1
Canadian Dollar Denominated2
Floating Rate Senior Notes due 20224.850% Senior Notes due 2022
Floating Rate Senior Notes due 20233.190% Senior Notes due 2022
2.900% Senior Notes due 20223.940% Senior Notes due 2023
4.000% Senior Notes due 20233.940% Senior Notes due 2023
0.550% Senior Notes due 20233.950% Senior Notes due 2024
3.500% Senior Notes due 20242.440% Senior Notes due 2025
2.500% Senior Notes due 20253.200% Senior Notes due 2027
4.250% Senior Notes due 20266.100% Senior Notes due 2028
1.600% Senior Notes due 20262.990% Senior Notes due 2029
3.700% Senior Notes due 20277.220% Senior Notes due 2030
3.125% Senior Notes due 20297.200% Senior Notes due 2032
2.500% Sustainability-linked Senior Notes due 20333.100% Sustainability-linked Senior Notes due 2033
4.500% Senior Notes due 20445.570% Senior Notes due 2035
5.500% Senior Notes due 20465.750% Senior Notes due 2039
4.000% Senior Notes due 20495.120% Senior Notes due 2040
3.400% Senior Notes due 20514.240% Senior Notes due 2042
4.570% Senior Notes due 2044
4.870% Senior Notes due 2044
4.100% Senior Notes due 2051
4.560% Senior Notes due 2064
1As at December 31, 2021, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$11 billion.
2As at December 31, 2021, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $9.2 billion.

Rule 3-10 of the US Securities and Exchange Commission's (SEC) Regulation S-X provides an exemption from the reporting requirements of the Securities Exchange Act of 1934, as amended (Exchange Act) for fully consolidated subsidiary issuers of guaranteed securities and subsidiary guarantors and allows for summarized financial information in lieu of filing separate financial statements for each of the Partnerships.

The following Summarized Combined Statement of Earnings and the Summarized Combined Statements of Financial Position combines the balances of EEP, SEP and Enbridge.

Summarized Combined Statement of Earnings
Year ended December 31, 2021
(millions of Canadian dollars)
Operating loss(64)
Earnings4,970
Earnings attributable to common shareholders4,604

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Summarized Combined Statements of Financial Position
December 31, 2021December 31, 2020
(millions of Canadian dollars)
Accounts receivable from affiliates3,442 2,108
Short-term loans receivable from affiliates4,947 4,926
Other current assets605 375
Long-term loans receivable from affiliates51,983 43,217
Other long-term assets3,732 4,237
Accounts payable to affiliates1,982 1,267
Short-term loans payable to affiliates2,891 4,117
Other current liabilities8,110 5,628
Long-term loans payable to affiliates41,370 32,035
Other long-term liabilities41,353 41,353

The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non-Guarantors.

Under US bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee:

received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;
was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or
intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under US federal or state law.

Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.

Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:

any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge’s direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;
the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;
the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement;
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with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;
with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or
with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.

The guarantee obligations of Enbridge of the Guaranteed Partnership Notes will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.

The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities.

LEGAL AND OTHER UPDATES

LIQUIDS PIPELINES

Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement
In 2019, the Michigan Attorney General filed a complaint in the Michigan Ingham County Circuit Court (the Court) that requests the Court to declare the easement granted in 1953 that we have for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits “as soon as possible after a reasonable notice period to allow orderly adjustments by affected parties”. On December 15, 2021, we removed the case to the US District Court in the Western District of Michigan (US District Court), where it was assigned to Judge Janet T. Neff. The removal of the Attorney General’s case to federal court follows a November 16, 2021 ruling (further described below) which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor to force Line 5’s shutdown raised important federal issues that should be heard in federal court. On December 21, 2021, the Attorney General made a request to file a remand motion and on December 28, 2021, we responded to her request to file that motion. On January 5, 2022, the court issued an Order allowing the Attorney General to file a motion to remand the 2019 case. The Attorney General’s motion and brief was filed on January 14, 2022, and our response is due on February 11, 2022. The motion is expected to be fully briefed by March 2022.

On November 13, 2020, the Governor of Michigan and the Director of the Michigan Department of Natural Resources notified us that the State of Michigan (the State) was revoking and terminating the easement granted in 1953 that allows Line 5 to operate across the Straits. The notice demanded that the portion of Line 5 that crosses the Straits must be shut down by May 2021. On November 24, 2020, we filed in the US District Court for the Western District of Michigan a Notice of Removal, which removed the State’s November Complaint to federal court, and a Complaint for Declaratory and Injunctive Relief that requests the US District Court to enjoin the Governor from taking any action to prevent or impede the operation of Line 5. US District Court Judge Neff was assigned to the cases and on November 16, 2021, Judge Neff issued an order denying the State’s motion to remand its 2020 case back to Ingham County Circuit Court ,finding that the case should remain in federal court. Judge Neff also ruled in our favor on our motion for additional briefing and granted the Government of Canada’s motion to file a supplemental brief, which reiterated that the 1977 Transit Pipelines Treaty between the US and Canada had been invoked in October and that the matter is of great importance to Canada. Subsequently, the Governor voluntarily dismissed the State’s lawsuit on November 30, 2021.

Our lawsuit to prohibit the Governor of Michigan and Director of the Michigan Department of Natural Resources from interfering with the operation of Line 5, remains in federal court. On November 30, 2021 the State made a request to Judge Neff to file a motion to dismiss the complaint. On the same date, we made a request to file a motion for summary judgment. Briefing on these motions began on January 18, 2022 and is scheduled to be complete by April 2022.

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In 2021, we completed the engineering and design phase of the Great Lakes Tunnel Project and we have begun the process of hiring a contractor to construct the tunnel. We continue to actively pursue state and federal regulatory permits from the US Army Corps of Engineers (Army Corps), the Michigan Department of Environment, Great Lakes & Energy (EGLE) and the Michigan Public Service Commission (MPSC). The EGLE permits were granted in the first quarter of 2021; one of the EGLE permits was challenged by the Bay Mills Indian Community. Dispositive motions are fully briefed and with the Administrative Law Judge for decision.

On June 23, 2021, the Army Corps announced they would proceed with an EIS for the Great Lakes Tunnel Project to replace Line 5 at the Straits. On June 23, 2021, we issued a statement stating that construction on this project would be delayed due to the EIS.

In the MPSC contested case proceeding, testimony has been filed, and the hearing took place during January 2022, with briefing scheduled to be complete by March 2022.

Dakota Access Pipeline
We own an effective interest of 27.6% in the Bakken Pipeline System, which is inclusive of DAPL. The Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed lawsuits in 2016 with the US Court for the District of Columbia (the District Court) contesting the lawfulness of the Army Corps easement for DAPL, including the adequacy of the Army Corps’ environmental review and tribal consultation process. The Oglala Sioux and Yankton Sioux Tribes also filed lawsuits alleging similar claims in 2018.

On June 14, 2017, the District Court found the Army Corps’ environmental review to be deficient and ordered the Army Corps to conduct further study concerning spill risks from DAPL. In August 2018, the Army Corps completed on remand the further environmental review ordered by the District Court and reaffirmed the issuance of the easement for DAPL. All four plaintiff Tribes subsequently amended their complaints to include claims challenging the adequacy of the Army Corps’ August 2018 remand decision.

On March 25, 2020, in response to amended complaints from the Tribes, the District Court found the Army Corps’ environmental review on remand was deficient and ordered the Army Corps to prepare an EIS to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July 6, 2020, the District Court issued an order vacating the Army Corps’ easement for DAPL and ordering that the pipeline be shut down by August 5, 2020. Dakota Access, LLC and the Army Corps appealed the decision and filed a motion for a stay pending appeal with the US Court of Appeals for the District of Columbia Circuit. On August 5, 2020, the US Court of Appeals stayed the District Court’s July 6 order to shut down and empty the pipeline, but did not stay the District Court’s March 25 order requiring the Army Corps to prepare an EIS or the District Court’s July 6 order vacating the DAPL easement.

On January 26, 2021, the US Court of Appeals affirmed the District Court’s decision, holding that the Army Corps is required to prepare an EIS and that the Army Corps’ easement for DAPL is vacated. Dakota Access, LLC has since filed a petition asking the US Supreme Court to review the decision that an EIS is required. The US Court of Appeals also determined that, absent considering the closure of DAPL in the context of an injunction proceeding, the District Court could not order DAPL’s operations to cease. While not an issue before the US Court of Appeals, the US Court of Appeals also recognized that the Army Corps could consider whether to allow DAPL to continue to operate in the absence of an easement. On September 20, 2021, DAPL requested that the US Supreme Court review the US Court of Appeals decision. That request, opposed by the US Government and the Tribes, remands pending.
On May 21, 2021, the District Court dismissed the plaintiff Tribes’ request for an injunction enjoining DAPL from operating until the Army Corps has completed its EIS. The right of the plaintiff Tribes to appeal the denial of the injunction request expired on July 20, 2021. The Army Corps earlier indicated that it did not intend, at that time, to exercise its authority to bar DAPL’s continued operation, notwithstanding the absence of an easement and that it anticipates completing its EIS by March 2022.

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On July 22, 2021, the Army Corps filed a notice with the District Court advising that the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a notice asserting violations of federal safety regulations resulting from the operation of DAPL. The Army Corps stated that it would consider PHMSA’s notice as part of its ongoing consideration of whether and how the Army Corps will enforce its rights on property crossed by the pipeline and in the context of the ongoing EIS. The Army Corps also granted the request from the Tribes to extend the EIS completion date to September 2022.

OTHER LITIGATION
We and our subsidiaries are involved in various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.

TAX MATTERS
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

CRITICAL ACCOUNTING ESTIMATES

Our consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States of America (US GAAP), which require management to make estimates, judgments and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. In making judgments and estimates, management relies on external information and observable conditions, where possible, supplemented by internal analysis as required. We believe our most critical accounting policies and estimates discussed below have an impact across the various segments of our business.

Business Combinations
We apply the provisions of Accounting Standards Codification (ASC) 805 Business Combinations in accounting for our acquisitions. The acquired long-lived assets, intangible assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. Goodwill represents the excess of the purchase price over the fair value of net assets. While we use our best estimates and assumptions to accurately value assets acquired and liabilities assumed at the date of acquisition, as well as any contingent consideration, our estimates are inherently uncertain and subject to refinement. During the measurement period, which may be up to one year from the acquisition date, we record adjustments to the assets acquired and liabilities assumed with the corresponding offset to goodwill. Upon the conclusion of the measurement period or final determination of values of assets acquired or liabilities assumed, whichever comes first, any subsequent adjustments are recorded to our consolidated statements of operations.

Accounting for business combinations requires significant judgment, estimates and assumptions at the acquisition date. In developing estimates of fair values at the acquisition date, we utilize a variety of factors including market data, historical and future expected cash flows, growth rates and discount rates. The subjective nature of our assumptions increases the risk associated with estimates surrounding the projected performance of the acquired entity.

Goodwill Impairment
Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired.

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We perform our impairment assessment annually on April 1 at the reporting unit level. Reporting units are determined by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar.

We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, assessment of macroeconomic trends, regulatory environments, capital accessibility, operating income trends, and industry conditions. Based on our assessment of the qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than it’s carrying amount, a quantitative goodwill impairment assessment is performed.

The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each corresponding reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. Fair value of our reporting units is estimated using a combination of discounted cash flow models and earnings multiples techniques. The determination of fair value using the discounted cash flow model technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. The cash flow projections include significant judgments and assumptions relating to discount rates and expected future capital expenditures. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units.

Our most recent annual assessment of the goodwill balance was performed on April 1, 2021. As at April 1, 2021, our reporting units were equivalent to our reportable segments. We performed a quantitative goodwill impairment assessment for the Gas Transmission and Midstream reporting unit and qualitative assessments for the Liquids Pipelines and Gas Distribution and Storage reporting units. Our goodwill impairment assessments did not result in an impairment charge. Also, we did not identify any indicators of goodwill impairment during the remainder of 2021.

Asset Impairment
We evaluate the recoverability of our property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal or regulatory changes, or other factors indicate we may not recover the carrying amount of our assets. We continually monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset, we will assess the fair value of the asset. An impairment loss is recognized when the carrying amount of the asset exceeds its fair value.

With respect to equity method investments, we assess at each balance sheet date whether there is objective evidence that the investment is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we determine whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the investment.

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Asset fair value is determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires the use of projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes to these projections and assumptions could result in revisions to the evaluation of the recoverability of the asset and the recognition of an impairment loss in the Consolidated Statements of Earnings.

Assets Held for Sale
We classify assets as held for sale when management commits to a formal plan to actively market an asset or a group of assets and when management believes it is probable the sale of the assets will occur within one year. We measure assets classified as held for sale at the lower of their carrying value and their estimated fair value less costs to sell.

Regulatory Accounting
Certain of our businesses are subject to regulation by various authorities, including but not limited to, the CER, the FERC, the Alberta Energy Regulator, La Régie de l’energie du Québec and the OEB. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities. Key determinants in the ratemaking process are:
Costs of providing service, including operating costs, capital invested, depreciation expense and taxes;
Allowed rate of return, including the equity component of the capital structure and related income taxes;
Interest costs on the debt component of the capital structure; and
Contract and volume throughput assumptions.

The allowed rate of return is determined in accordance with the applicable regulatory model and may impact our profitability. The rates for a number of our projects are based on a cost-of-service recovery model that follows the regulators’ authoritative guidance. Under the cost-of-service tolling methodology, we calculate tolls based on forecast volumes and cost. A difference between forecast and actual results causes an over or under recovery in any given year. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the CER’s Land Matters Consultation Initiative (LMCI) and for future removal and site restoration costs as approved by the OEB.

To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates.

As at December 31, 2021 and 2020, our regulatory assets totaled $5.9 billion and $5.6 billion, respectively, and regulatory liabilities totaled $3.4 billion and $3.4 billion, respectively.

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Depreciation
Depreciation of property, plant and equipment, our largest asset with a net book value at December 31, 2021 and 2020, of $100.1 billion and $94.6 billion, respectively, is charged in accordance with two primary methods. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated depreciation.

When it is determined that the estimated service life of an asset no longer reflects the expected remaining period of benefit, prospective changes are made to the estimated service life. Estimates of useful lives are based on third party engineering studies, experience and/or industry practice. There are a number of assumptions inherent in estimating the service lives of our assets including the level of development, exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by our pipelines as well as the demand for crude oil and natural gas and the integrity of our systems. Changes in these assumptions could result in adjustments to the estimated service lives, which could result in material changes to depreciation expense in future periods in any of our business segments. For certain rate-regulated operations, depreciation rates are approved by the regulator and the regulator may require periodic studies or technical updates on useful lives which may change depreciation rates.

Pension and Other Postretirement Benefits
We use certain assumptions relating to the calculation of defined benefit pension and other postretirement liabilities and net periodic benefit costs. These assumptions comprise management’s best estimates of expected return on plan assets, future salary levels, other cost escalations, retirement ages of employees and other actuarial factors including discount rates and mortality. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments anticipated to be made under each of the respective plans. The expected return on plan assets is determined using market-related values and assumptions on the asset mix consistent with the investment policy relating to the assets and their projected returns. The assumptions are reviewed annually by our independent actuaries. Actual results that differ from results based on assumptions are amortized over future periods and, therefore, could materially affect the expense recognized and the recorded obligation in future periods.

The following sensitivity analysis identifies the impact on the December 31, 2021 Consolidated Financial Statements of a 0.5% change in key pension and other postretirement benefit obligations (OPEB) assumptions:
 CanadaUnited States
 ObligationExpenseObligationExpense
(millions of Canadian dollars)    
Pension
Decrease in discount rate378 31 70 
Decrease in expected return on assets— 21 — 
Decrease in rate of salary increase(71)(15)(6)(2)
OPEB
Decrease in discount rate21 — 
Decrease in expected return on assets N/A N/A— 

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Contingent Liabilities
Provisions for claims filed against us are determined on a case-by-case basis. Case estimates are reviewed on a regular basis and are updated as new information is received. The process of evaluating claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the final determination of which could have a material impact on our financial results and certain subsidiaries and investments are detailed in Part II. Item 8. Financial Statements and Supplementary Data - Note 30. Commitments and Contingencies. In addition, any unasserted claims that later may become evident could have a material impact on our financial results and certain subsidiaries and investments.

Asset Retirement Obligations
Asset Retirement Obligations (ARO) associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. The discount rates used to estimate the present value of the expected future cash flows for the year ended December 31, 2021 ranged from 0.9% to 9.0% (2020 - 1.8% to 9.0%). ARO is added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, there is insufficient data or information to reasonably determine the timing of settlement for estimating the fair value of the ARO. In these cases, the ARO cost is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset.

In 2009, the CER issued a decision related to the LMCI, which required holders of an authorization to operate a pipeline under the CER Act to file a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The CER's decision stated that while pipeline companies are ultimately responsible for the full costs of abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable from the users of the pipeline upon approval by the CER. Following the CER's final approval of the collection mechanism and the set-aside mechanism for LMCI, we began collecting and setting aside funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trust in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues and Restricted long-term investments. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities.

The Minnesota Public Utilities Commission (MPUC), in its June 28, 2018 decision granting the Line 3 Replacement Project’s Certificate of Need, required Enbridge to establish and fund a decommissioning trust (Decommissioning Trust Fund) for the purpose of funding the cost of retiring Line 3 Replacement Project assets at the end of their useful lives. Further to the Certificate of Need decision, in late 2021 the MPUC established a process for the purpose of determining the terms and conditions of the Decommissioning Trust Fund. Enbridge anticipates this MPUC process to be completed in 2022, with a decision from the MPUC in the second half of 2022. Enbridge expects to recover contributions necessary to fund the Decommissioning Trust Fund from its shippers through rates.

CHANGES IN ACCOUNTING POLICIES

Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 3. Changes in Accounting Policies.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price.

The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.
Foreign Exchange Risk
We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in US dollar denominated investments and subsidiaries using foreign currency derivatives and US dollar denominated debt.
Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a program to mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 3.9%.

We are exposed to changes in the fair value of fixed rate debt that arise as a result of changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in fair value via execution of fixed to floating interest rate swaps. As at December 31, 2021, we do not have any pay floating-receive fixed interest rate swaps outstanding.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 2.0%.
Commodity Price Risk
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.
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Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

Market Risk Management
We have a Risk Policy to minimize the likelihood that adverse cash flow impacts arising from movements in market prices will exceed a defined risk tolerance. We identify and measure all material market risks including commodity price risks, interest rate risks, foreign exchange risk and equity price risk using a standardized measurement methodology. Our market risk metric consolidates the exposure after accounting for the impact of offsetting risks and limits the consolidated cash flow volatility arising from market related risks to an acceptable approved risk tolerance threshold. Our market risk metric is Cash Flow at Risk (CFaR).

CFaR is a statistically derived measurement used to measure the maximum cash flow loss that could potentially result from adverse market price movements over a one month holding period for price sensitive non-derivative exposures and for derivative instruments we hold or issue as recorded on the Consolidated Statements of Financial Position as at December 31, 2021. CFaR assumes that no further mitigating actions are taken to hedge or otherwise minimize exposures and the selection of a one month holding period reflects the mix of price risk sensitive assets at Enbridge. As a practical matter, a large portion of Enbridge’s exposure could be hedged or unwound in a much shorter period if required to mitigate the risks.

The consolidated CFaR policy limit for Enbridge is 3.5% of its forward 12 month normalized cash flow. At December 31, 2021 and 2020 CFaR was $103 million and $128 million or 0.9% and 1.2%, respectively, of estimated 12 month forward normalized cash flow.

LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. We also maintain current shelf prospectuses with securities regulators which enables ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2021. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.
CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.
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We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances.

FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

To the Shareholders and Board of Directors of Enbridge Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated statements of financial position of Enbridge Inc. and its subsidiaries (together, the Company) as of December 31, 2021 and 2020, and the related consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

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Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
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Goodwill impairment assessment
As described in Notes 2 and 16 to the consolidated financial statements, the Company’s goodwill balance was $32,775 million at December 31, 2021. As disclosed by management, an annual goodwill impairment assessment is performed at the reporting unit level as of April 1 of each year, or more frequently if events or circumstances indicate that the carrying value of goodwill may be impaired. Management has the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. In making the qualitative assessment, management considers macroeconomic trends, changes to regulatory environments, capital accessibility, operating income trends, and changes to industry conditions. The quantitative goodwill impairment assessment involves determining the fair value of the Company’s reporting units and comparing those values to the carrying value of each reporting unit, including goodwill. Fair value is estimated using a combination of discounted cash flow and earnings multiples techniques. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, expected future capital expenditures and working capital levels. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units. In the current year, the quantitative goodwill impairment assessment was performed for the Gas Transmission and Midstream (Gas Transmission) reporting unit, while the qualitative goodwill impairment assessments were performed for the Liquids Pipelines and Gas Distribution and Storage reporting units.
The principal considerations for our determination that performing procedures relating to the goodwill impairment assessment is a critical audit matter are the significant judgment required by management when (i) developing the significant assumptions related to operating income trends used in the qualitative assessment for all reporting units outside of the Gas Transmission reporting unit, and (ii) developing such significant assumptions as discount rates, projected operating income, expected future capital expenditures and earnings multipliers used to estimate the fair value of the Gas Transmission reporting unit. This led to a high degree of auditor judgment, effort and subjectivity in performing procedures to evaluate the reasonableness of management’s significant assumptions used in the qualitative assessment and the quantitative assessment of the Gas Transmission reporting unit. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in performing the procedures and evaluating the audit evidence obtained over the quantitative assessment.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s goodwill impairment assessment, including controls over (i) the development of significant assumptions related to operating income trends used in the qualitative assessment and (ii) the determination of the fair value estimate of the Gas Transmission reporting unit. These procedures also included, among others (i) evaluating the reasonableness of significant assumptions used by management in the qualitative assessment of the Company’s reporting units, specifically those related to operating income trends and (ii) testing management’s process for developing the fair value estimate of the Gas Transmission reporting unit. Testing management’s process for developing the fair value estimate of the Gas Transmission reporting unit included evaluating the appropriateness of the discounted cash flow and the earnings multiples models; testing the completeness, accuracy, and relevance of underlying data used in the models; and evaluating the reasonableness of significant assumptions used by management in determining the fair value estimate including discount rates, projected operating income, expected future capital expenditures and earnings multipliers.
95


Assessing the reasonableness of projected operating income and its trends, and expected future capital expenditures, involved evaluating whether these significant assumptions were reasonable considering the current and past performance of the Company’s reporting units, external industry data, and evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of management’s discounted cash flow and earnings multiples models and evaluating the reasonableness of assumptions used in the models, specifically discount rates and earnings multipliers.

/s/PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Canada
February 11, 2022
We have served as the Company's auditor since 1949.












96


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS
Year ended December 31,202120202019
(millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales26,873 19,259 29,309 
Gas distribution sales4,026 3,663 4,205 
Transportation and other services16,172 16,165 16,555 
Total operating revenues (Note 4)
47,071 39,087 50,069 
Operating expenses
Commodity costs26,608 18,890 28,802 
Gas distribution costs2,094 1,779 2,202 
Operating and administrative6,712 6,749 6,991 
Depreciation and amortization3,852 3,712 3,391 
Impairment of long-lived assets — 423 
Total operating expenses39,266 31,130 41,809 
Operating income7,805 7,957 8,260 
Income from equity investments (Note 13)
1,711 1,136 1,503 
Impairment of equity investments (Note 13)
(111)(2,351)— 
Other income/(expense)
Net foreign currency gain286 181 477 
Gain/(loss) on dispositions319 (17)(300)
Other374 74 258 
Interest expense (Note 18)
(2,655)(2,790)(2,663)
Earnings before income taxes7,729 4,190 7,535 
Income tax expense (Note 25)
(1,415)(774)(1,708)
Earnings6,314 3,416 5,827 
Earnings attributable to noncontrolling interests(125)(53)(122)
Earnings attributable to controlling interests6,189 3,363 5,705 
Preference share dividends(373)(380)(383)
Earnings attributable to common shareholders5,816 2,983 5,322 
Earnings per common share attributable to common shareholders (Note 6)
2.87 1.48 2.64 
Diluted earnings per common share attributable to common shareholders (Note 6)
2.87 1.48 2.63 
The accompanying notes are an integral part of these consolidated financial statements.
97


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year ended December 31,202120202019
(millions of Canadian dollars)
Earnings6,314 3,416 5,827 
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges162 (457)(437)
Change in unrealized gain on net investment hedges49 102 281 
Other comprehensive income/(loss) from equity investees(12)(1)40 
Excluded components of fair value hedges(5)— 
Reclassification to earnings of loss on cash flow hedges235 198 127 
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts21 13 13 
Reclassification to earnings of gain on equity investees(62)— — 
Actuarial gain/(loss) on pension and OPEB394 (167)(96)
Foreign currency translation adjustments(507)(853)(3,035)
Other comprehensive income/(loss), net of tax275 (1,160)(3,107)
Comprehensive income6,589 2,256 2,720 
Comprehensive income attributable to noncontrolling interests(95)(22)(7)
Comprehensive income attributable to controlling interests6,494 2,234 2,713 
Preference share dividends(373)(380)(383)
Comprehensive income attributable to common shareholders6,121 1,854 2,330 
The accompanying notes are an integral part of these consolidated financial statements.

98


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Year ended December 31,202120202019
(millions of Canadian dollars, except per share amounts)
Preference shares (Note 21)
   
Balance at beginning and end of year7,747 7,747 7,747 
Common shares (Note 21)
Balance at beginning of year64,768 64,746 64,677 
Shares issued on exercise of stock options31 22 69 
Balance at end of year64,799 64,768 64,746 
Additional paid-in capital
Balance at beginning of year277 187 — 
Stock-based compensation28 30 34 
Repurchase of noncontrolling interest — 65 
Options exercised(23)(21)(61)
Change in reciprocal interest98 76 117 
Other(15)32 
Balance at end of year365 277 187 
Deficit   
Balance at beginning of year(9,995)(6,314)(5,538)
Earnings attributable to controlling interests6,189 3,363 5,705 
Preference share dividends(373)(380)(383)
Common share dividends declared(6,818)(6,612)(6,125)
Dividends paid to reciprocal shareholder8 17 18 
Modified retrospective adoption of ASU 2016-13 Financial Instruments - Credit Losses
 (66)— 
Other (3)
Balance at end of year(10,989)(9,995)(6,314)
Accumulated other comprehensive income/(loss) (Note 23)
Balance at beginning of year(1,401)(272)2,672 
Other comprehensive income/(loss) attributable to common shareholders, net of tax305 (1,129)(2,992)
Other — 48 
Balance at end of year(1,096)(1,401)(272)
Reciprocal shareholding
Balance at beginning of year(29)(51)(88)
Change in reciprocal interest29 22 37 
Balance at end of year (29)(51)
Total Enbridge Inc. shareholders’ equity60,826 61,367 66,043 
Noncontrolling interests (Note 20)
   
Balance at beginning of year2,996 3,364 3,965 
Earnings attributable to noncontrolling interests125 53 122 
Other comprehensive loss attributable to noncontrolling interests, net of tax
Change in unrealized loss on cash flow hedges(15)(6)(7)
Foreign currency translation adjustments(15)(25)(108)
 (30)(31)(115)
Comprehensive income attributable to noncontrolling interests95 22 
Distributions(271)(300)(254)
Contributions15 23 12 
Redemption of noncontrolling interests(293)(112)(300)
Repurchase of noncontrolling interest — (65)
Other (1)(1)
Balance at end of year2,542 2,996 3,364 
Total equity63,368 64,363 69,407 
Dividends paid per common share3.34 3.24 2.95 
The accompanying notes are an integral part of these consolidated financial statements.

99


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,202120202019
(millions of Canadian dollars)
Operating activities   
Earnings6,314 3,416 5,827 
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization3,852 3,712 3,391 
Deferred income tax expense (Note 25)
1,091 447 1,156 
Unrealized derivative fair value gain, net (Note 24)
(173)(756)(1,751)
Income from equity investments(1,711)(1,136)(1,503)
Distributions from equity investments1,630 1,392 1,804 
Impairment of long-lived assets — 423 
Impairment of equity investments111 2,351 — 
(Gain)/loss on dispositions(319)(6)254 
Other77 268 56 
Changes in operating assets and liabilities (Note 28)
(1,616)93 (259)
Net cash provided by operating activities9,256 9,781 9,398 
Investing activities   
Capital expenditures(7,818)(5,405)(5,492)
Long-term investments and restricted long-term investments(640)(487)(1,159)
Distributions from equity investments in excess of cumulative earnings533 705 417 
Additions to intangible assets(275)(215)(200)
Acquisitions(3,785)(24)— 
Proceeds from dispositions1,263 265 2,110 
Affiliate loans, net65 (16)(314)
Other — (20)
Net cash used in investing activities(10,657)(5,177)(4,658)
Financing activities
Net change in short-term borrowings394 223 (127)
Net change in commercial paper and credit facility draws2,960 1,542 825 
Debenture and term note issues, net of issue costs8,032 5,230 6,176 
Debenture and term note repayments(2,264)(4,463)(4,668)
Contributions from noncontrolling interests15 23 12 
Distributions to noncontrolling interests(271)(300)(254)
Common shares issued5 18 
Preference share dividends(367)(380)(383)
Common share dividends(6,766)(6,560)(5,973)
Redemption of preferred shares held by subsidiary (Note 20)
(415)— (300)
Other(87)(90)(71)
Net cash provided by/(used in) financing activities1,236 (4,770)(4,745)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash(5)(20)44 
Net increase/(decrease) in cash and cash equivalents and restricted cash(170)(186)39 
Cash and cash equivalents and restricted cash at beginning of year490 676 637 
Cash and cash equivalents and restricted cash at end of year320 490 676 
Supplementary cash flow information  
Cash paid for income taxes489 524 571 
Cash paid for interest, net of amount capitalized2,427 2,538 2,738 
Property, plant and equipment non-cash accruals831 801 730 
The accompanying notes are an integral part of these consolidated financial statements.

100


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
December 31,20212020
(millions of Canadian dollars; number of shares in millions)
Assets  
Current assets  
Cash and cash equivalents286 452 
Restricted cash34 38 
Accounts receivable and other (Note 9)
6,862 5,258 
Accounts receivable from affiliates107 66 
Inventory (Note 10)
1,670 1,536 
 8,959 7,350 
Property, plant and equipment, net (Note 11)
100,067 94,571 
Long-term investments (Note 13)
13,324 13,818 
Restricted long-term investments (Note 14)
630 553 
Deferred amounts and other assets8,613 8,446 
Intangible assets, net (Note 15)
4,008 2,080 
Goodwill (Note 16)
32,775 32,688 
Deferred income taxes (Note 25)
488 770 
Total assets168,864 160,276 
Liabilities and equity  
Current liabilities  
Short-term borrowings (Note 18)
1,515 1,121 
Accounts payable and other (Note 17)
9,767 9,228 
Accounts payable to affiliates90 22 
Interest payable693 651 
Current portion of long-term debt (Note 18)
6,164 2,957 
 18,229 13,979 
Long-term debt (Note 18)
67,961 62,819 
Other long-term liabilities7,617 8,783 
Deferred income taxes (Note 25)
11,689 10,332 
105,496 95,913 
Commitments and contingencies (Note 30)
00
Equity
Share capital (Note 21)
Preference shares7,747 7,747 
Common shares (2,026 outstanding at December 31, 2021 and 2020)
64,799 64,768 
Additional paid-in capital365 277 
Deficit(10,989)(9,995)
Accumulated other comprehensive loss (Note 23)
(1,096)(1,401)
Reciprocal shareholding (29)
Total Enbridge Inc. shareholders’ equity60,826 61,367 
Noncontrolling interests (Note 20)
2,542 2,996 
 63,368 64,363 
Total liabilities and equity168,864 160,276 
Variable Interest Entities (VIE) (Note 12)
The accompanying notes are an integral part of these consolidated financial statements.

101


NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
INDEX
  Page
1.Business Overview
2.Significant Accounting Policies
3.Changes in Accounting Policies
4.Revenue
5.Segmented Information
6.Earnings per Common Share
7.Regulatory Matters
8.Acquisitions and Dispositions
9.Accounts Receivable and Other
10.Inventory
11.Property, Plant and Equipment
12.Variable Interest Entities
13.Long-Term Investments
14.Restricted Long-Term Investments
15.Intangible Assets
16.Goodwill
17.Accounts Payable and Other
18.Debt
19.Asset Retirement Obligations
20.Noncontrolling Interests
21.Share Capital
22.Stock Option and Stock Unit Plans
23.Components of Accumulated Other Comprehensive Income/(Loss)
24.Risk Management and Financial Instruments
25.Income Taxes
26.Pension and Other Postretirement Benefits
27.Leases
28.Changes in Operating Assets and Liabilities
29.Related Party Transactions
30.Commitments and Contingencies
31.Guarantees
32.Quarterly Financial Data (Unaudited)

102


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 5 business segments: Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation, and Energy Services. These reporting segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

LIQUIDS PIPELINES
Liquids Pipelines consists of pipelines and terminals in Canada and the United States (US) that transport various grades of crude oil and other liquid hydrocarbons, including the Mainline System, Regional Oil Sands System, Gulf Coast and Mid-Continent, Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and Other. This segment also includes Moda Midstream Operating, LLC (Moda) which was acquired on October 12, 2021 (Note 8) and is a component of Gulf Coast and Mid-Continent.

GAS TRANSMISSION AND MIDSTREAM
Gas Transmission and Midstream consists of our investments in natural gas pipelines and gathering and processing facilities in Canada and the US, including US Gas Transmission, Canadian Gas Transmission, US Midstream and Other.

GAS DISTRIBUTION AND STORAGE
Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge Gas Inc. (Enbridge Gas), which serves residential, commercial and industrial customers located throughout Ontario. This business segment also includes natural gas distribution activities in Québec and an investment in Noverco Inc. (Noverco). We sold our investment in Noverco to Trencap L.P. on December 30, 2021 (Note 13).

RENEWABLE POWER GENERATION
Renewable Power Generation consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery and transmission assets. In North America, assets are primarily located in the provinces of Alberta, Saskatchewan, Ontario and Québec, and in the states of Colorado, Texas, Indiana and West Virginia. We also have offshore wind assets in operation and under development in the United Kingdom, Germany and France.

ENERGY SERVICES
Our Energy Services businesses in Canada and the US undertake physical commodity marketing activity and logistical services to manage our volume commitments on various pipeline systems. Energy Services also provides energy marketing services to North American refiners, producers and other customers.

ELIMINATIONS AND OTHER
In addition to the business segments noted above, Eliminations and Other includes operating and administrative costs that are not allocated to business segments as well as a foreign exchange hedging program. Eliminations and Other also includes new business development activities and corporate investments.

103


2. SIGNIFICANT ACCOUNTING POLICIES

These consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (US GAAP). Amounts are stated in Canadian dollars unless otherwise noted. As a Securities and Exchange Commission (SEC) registrant, we are permitted to use US GAAP for the purposes of meeting both our Canadian and US continuous disclosure requirements.

BASIS OF PRESENTATION AND USE OF ESTIMATES
The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: variable consideration included in revenue (Note 4); carrying values of regulatory assets and liabilities (Note 7); purchase price allocations (Note 8); unbilled revenues; expected credit losses; depreciation rates and carrying value of property, plant and equipment (Note 11); amortization rates and carrying value of intangible assets (Note 15); measurement of goodwill (Note 16); fair value of asset retirement obligations (ARO) (Note 19); valuation of stock-based compensation (Note 22); fair value of financial instruments (Note 24); provisions for income taxes (Note 25); assumptions used to measure retirement benefits and OPEB (Note 26); commitments and contingencies (Note 30); and estimates of losses related to environmental remediation obligations (Note 30). Actual results could differ from these estimates.

Certain comparative figures in our consolidated financial statements have been reclassified to conform to the current year's presentation.

PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include our accounts and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE entity that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We assess the primary beneficiary determination for a VIE on an ongoing basis if there are changes in the facts and circumstances related to a VIE. If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses.

104


All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method.

REGULATION
Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the Canada Energy Regulator (CER), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, the Ontario Energy Board (OEB) and La Régie de l’energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities.

Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the CER’s Land Matters Consultation Initiative (LMCI). Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. We believe that the recovery of our regulatory assets as at December 31, 2021 is probable over the periods described in Note 7 - Regulatory Matters.

Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. The corresponding impact on earnings is included in Interest expense for the interest component and Other income/(expense) for the equity component. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation relating to the equity component would not be recognized.

Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified.

With the approval of regulators, certain operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred.

For certain regulated operations to which US GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with US GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with US GAAP and no regulatory asset is recorded.

105


REVENUE RECOGNITION
For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer creditworthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received.

Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts ratably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote.

Certain offshore pipeline transportation contracts require us to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay us a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received.

For the years ended December 31, 2021, 2020 and 2019, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $127 million, $292 million and $169 million, respectively.

For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utility revenues are recorded based on regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise areas.

Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded on a gross basis as the related contracts are not held for trading purposes and we are acting as the principal in the transactions.

Our largest non-affiliated customer accounted for approximately 13.5% of our third-party revenues for the year ended December 31, 2021 and 13.6% for the year ended December 31, 2020. No non-affiliated customer exceeded 10% of our third-party revenues for the year ended December 31, 2019.
DERIVATIVE INSTRUMENTS AND HEDGING
Non-qualifying Derivatives
Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Commodity sales, Transportation and other services revenue, Commodity costs, Operating and administrative expense, Net foreign currency gain/(loss) and Interest expense.

106


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 provided by operating activities beforehedges, fair value hedges or net investment hedges.

Cash Flow Hedges
We use cash flow hedges to manage our exposure to changes in operatingcommodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings.

If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized in earnings concurrently with the related transaction. If an anticipated hedged transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur.

Fair Value Hedges
We may use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged risk of the asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged risk of the asset or liability ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item.

Net Investment Hedges
Gains and losses arising from the translation of our net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA), a component of OCI. We currently have designated a portion of our US dollar denominated debt, as well as a portfolio of foreign exchange forward contracts in prior periods, as a hedge of our net investment in US dollar denominated investments and subsidiaries. As a result, the change in fair value of the foreign currency derivatives as well as the translation of US dollar denominated debt are reflected in OCI. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from the disposal of a foreign operation.

Classification of Derivatives
We recognize the fair value of derivative instruments in the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current.

Cash inflows and outflows related to derivative instruments are classified as Operating activities in the Consolidated Statements of Cash Flows.

Balance Sheet Offset
Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis.

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Transaction Costs
Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account for these costs as a reduction to Long-term debt in the Consolidated Statements of Financial Position. These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense.

EQUITY INVESTMENTS
Equity investments over which we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for our proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to, and decreased for distributions received from, the investee. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, we capitalize interest costs associated with the investment during such period.

RESTRICTED LONG-TERM INVESTMENTS
Long-term investments that are restricted as to withdrawal or usage, for the purposes of the CER’s LMCI, are presented as Restricted long-term investments in the Consolidated Statements of Financial Position.

OTHER INVESTMENTS
Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not have readily determinable fair values as other investments measured using the fair value measurement alternative (FVMA). These investments are recorded at cost minus impairment, if any, plus or minus the impact of observable price changes occurring in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the FVMA are reviewed for impairment each reporting period and written down to their fair value if objective evidence of impairment is identified. Equity investments with readily determinable fair values are measured at fair value through earnings. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established.

Investments in debt securities are classified as available-for-sale and measured at fair value through OCI.

NONCONTROLLING INTERESTS
Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position.

INCOME TAXES
Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities (includingare recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent that taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income tax expense.

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FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION
Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated to the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting from the translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise.

Gains and losses arising from the translation of foreign operations' functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect as at the balance sheet date, while revenues and expenses are translated using monthly average exchange rates.

CASH AND CASH EQUIVALENTS
Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased.

RESTRICTED CASH
Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as Restricted cash in the Consolidated Statements of Financial Position.

LOANS AND RECEIVABLES
Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. Interest income is recognized in earnings as it is earned with the passage of time.

CURRENT EXPECTED CREDIT LOSSES
For accounts receivable, a loss allowance matrix is utilized to measure lifetime expected credit losses. The matrix contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations. Other loan receivables and applicable off-balance sheet commitments utilize a discounted cash flow methodology which calculates the current expected credit losses based on historical default probability rates associated with the credit rating of the counterparty and the related term of the loan or commitment, adjusted for forward-looking information and management expectations.

NATURAL GAS IMBALANCES
The Consolidated Statements of Financial Position include balances as a result of differences in gas volumes received from, and delivered for, customers. As settlement of certain imbalances is in-kind, changes in environmental liabilities)the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates.

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INVENTORY
Inventory is comprised of natural gas held in storage by Enbridge Gas, crude oil and natural gas held primarily by businesses in the Energy Services segment and materials and supplies. Natural gas held in storage by Enbridge Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of gas purchased is deferred as a liability for future refund, or as an asset for collection as approved by the OEB. Other inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs in the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. Materials and supplies inventory is recorded at the lower of average cost or net realizable value.

PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component.
NaN primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in-service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation.

LEASES
We recognize an arrangement as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We recognize right-of-use (ROU) assets and the related lease liabilities in the Consolidated Statements of Financial Position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach applied for other long-lived assets.

Lease liabilities and ROU assets require the use of judgment and estimates which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing.

DEFERRED AMOUNTS AND OTHER ASSETS
Deferred amounts and other assets primarily consists of costs that regulatory authorities have permitted, or are expected to permit, to be recovered through future rates, including: deferred income taxes; the fair value adjustment to long-term debt; actual cost of removal of previously retired or decommissioned plant assets; and actuarial gains and losses arising from defined benefit pension plans.

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INTANGIBLE ASSETS
Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects. Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due.

GOODWILL
Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1.

We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar.

We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, the assessment of macroeconomic trends, regulatory environments, capital accessibility, operating income trends and industry conditions. Based on our assessment of qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less distributionsthan 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 noncontrolling intereststhe 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 redeemable noncontrolling interests, preference share dividendsearnings multiples techniques. The determination of fair value using the discounted cash flow technique requires the use of estimates and maintenanceassumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. Cash flow projections include significant judgments and assumptions relating to discount rates and expected future capital expenditures. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units.

The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of businesses included in the relevant reporting unit.

On April 1, 2021, we performed a quantitative goodwill impairment assessment for the Gas Transmission and Midstream reporting unit and qualitative assessments for the Liquids Pipelines and Gas Distribution and Storage reporting units. Our goodwill impairment assessments did not result in an impairment charge. Also, we did not identify any indicators of goodwill impairment during the remainder of 2021.

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IMPAIRMENT
We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, we will calculate fair value based on the discounted cash flows and write the asset down to the extent that the carrying value exceeds the fair value.

With respect to investments in debt securities and equity investments, we assess at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we value the expected discounted cash flows using observable market inputs. We determine whether the decline below carrying value is other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities. If the decline is determined to be other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset.

ASSET RETIREMENT OBLIGATIONS
ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. Fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements.

PENSION AND OTHER POSTRETIREMENT BENEFITS
We sponsor defined benefit and defined contribution pension plans, and defined benefit OPEB plans, which provide group health care, life insurance benefits and other postretirement benefits.

Defined benefit pension obligation and net periodic benefit cost are estimated using the projected unit credit method, which incorporates management’s best estimates of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors, including discount rates and mortality. The OPEB benefit obligation and net periodic benefit cost are estimated using the projected unit credit method, where benefits are attributed to years of service, taking into consideration projection of benefit costs.

We use mortality tables issued by the Society of Actuaries in the US (revised in 2021) and the Canadian Institute of Actuaries (revised in 2014) to measure the benefit obligations of our US pension plans (the US Plans) and our Canadian pension plans (the Canadian Plans), respectively.

We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments we anticipate making under each of the respective plans.

Funded pension and OPEB plan assets are measured at fair value. The expected return on funded pension and OPEB plan assets is determined using market-related values and assumptions on the invested asset mix consistent with the investment policies relating to the plan assets. The market-related values reflect estimated return on investments consistent with long-term historical averages for similar assets.

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

The excess of the fair value of a plan’s assets over the fair value of a plan’s benefit obligation is recognized as Deferred amounts and other assets in the Consolidated Statements of Financial Position. The excess of the fair value of a plan’s benefit obligation over the fair value of a plan’s assets is recognized as Accounts payable and other and Other long-term liabilities in the Consolidated Statements of Financial Position.

Net periodic benefit cost is charged to earnings and includes:
cost of benefits provided in exchange for employee services rendered during the year (current service cost);
interest cost of plan obligations;
expected return on plan assets (for funded pension and OPEB plans);
amortization of prior service costs on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans; and
amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans.

Cumulative unrecognized net actuarial gains and losses and prior service costs arising from defined benefit pension plans for our non-utility operations and from defined benefit OPEB plans are presented as a component of AOCI in the Consolidated Statements of Changes in Equity. Any unrecognized actuarial gains and losses and prior service costs and credits related to those plans that arise during the period are recognized as a component of OCI, net of tax. Cumulative unrecognized net actuarial gains and losses and prior service costs arising from defined benefit pension plans for our utility operations, which have been permitted or are expected to be permitted by the regulators, to be recovered through future rates, are presented as a component of Deferred amounts and other assets in the Consolidated Statements of
Financial Position.

Our utility operations also record regulatory adjustments to reflect the difference between certain net periodic benefit costs for accounting purposes and net periodic benefit costs for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent net periodic benefit costs are expected to be collected from or refunded to customers, respectively, in future rates. In the absence of rate regulation, regulatory assets or liabilities would not be recorded and net periodic benefit costs would be charged to earnings and OCI on an accrual basis.

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

STOCK-BASED COMPENSATION
Incentive Stock Options (ISO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISO granted as calculated by the Black-Scholes-Merton model and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility, with a corresponding credit to Additional paid-in capital. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised.

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Performance Stock Units (PSU) and Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each reporting period. PSUs vest at the completion of a three-year term and RSUs vest one-third annually from the grant date. During the vesting term, compensation expense is recorded based on the number of units outstanding and the current market price of Enbridge’s shares with an offset to Accounts payable and other or to Other long-term liabilities. The value of the PSUs is also dependent on our performance relative to performance targets set out under the plan.

COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in Accounts payable and other and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in the Consolidated Statements of Financial Position.

Liabilities for other commitments and contingencies are recognized when, after fully analyzing available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred, and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we recognize the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. We expense legal costs associated with loss contingencies as such costs are incurred.

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3.  CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES
There were no changes in accounting policies during the year ended December 31, 2021.

ADOPTION OF NEW ACCOUNTING STANDARDS
Accounting for Contract Assets and Liabilities from Contracts with Customers in a Business Combination
Effective November 1, 2021, we adopted Accounting Standards Update (ASU) 2021-08 on a retrospective basis beginning January 1, 2021. The new standard was issued in October 2021 to amend business combination accounting specific to contract assets and contract liabilities resulting from contracts with customers, requiring measurement in accordance with Accounting Standards Codification (ASC) 606. The ASU is also applicable to contract assets and contract liabilities from other contracts to which ASC 606 applies, such as contract liabilities from the sale of nonfinancial assets within the scope of ASC 610-20. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Reference Rate Reform
For eligible hedging relationships existing as at January 1, 2021 and prospectively, we have applied the optional expedient in ASU 2020-04 whereby the modification of the hedging instrument does not result in an automatic hedging relationship de-designation. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Clarifying Interaction Between Equity Securities, Equity Method Investments and Derivatives
Effective January 1, 2021, we adopted ASU 2020-01 on a prospective basis. The new standard was issued in January 2020 and clarifies that observable transactions should be considered for the purpose of applying the measurement alternative in accordance with ASC 321 Investments - Equity Securities immediately before the application or upon discontinuance of the equity method of accounting. Furthermore, the ASU clarifies that forward contracts or purchased options on equity securities are not out of scope of ASC 815 Derivatives and Hedging guidance only because, upon the contracts' exercise, the equity securities could be accounted for under the equity method of accounting or fair value option. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Accounting for Income Taxes
Effective January 1, 2021, we adopted ASU 2019-12 on a prospective basis. The new standard was issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting update removes certain exceptions to the general principles in ASC 740 Income Taxes as well as provides simplification by clarifying and amending existing guidance. The adoption of this ASU did not have a material impact on our consolidated financial statements.

FUTURE ACCOUNTING POLICY CHANGES
Disclosures About Government Assistance
ASU 2021-10 was issued in November 2021 to increase the transparency of government assistance to business entities. The ASU adds new disclosure requirements for transactions with government that are accounted for using a grant or contribution accounting model by analogy. The required disclosures include information about the nature of transactions, accounting policy applied, impacted financial statement line items and significant terms and conditions. ASU 2021-10 is effective January 1, 2022 and can be applied either prospectively or retrospectively with early adoption permitted. The adoption of ASU 2021-10 is not expected to have a material impact on our consolidated financial statements.

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Accounting for Certain Lessor Leases with Variable Lease Payments
ASU 2021-05 was issued in July 2021 to amend lessor accounting for certain leases with variable lease payments that do not depend on a reference index or a rate and would have resulted in the recognition of a loss at lease commencement if classified as a sales-type or a direct financing lease. The ASU amends the classification requirements of such leases for lessors to result in an operating lease classification. ASU 2021-05 is effective January 1, 2022 and can be applied either retrospectively or prospectively with early adoption permitted. The adoption of ASU 2021-05 is not expected to have a material impact on our consolidated financial statements.

Accounting for Modifications or Exchanges of Certain Equity-Classified Contracts
ASU 2021-04 was issued in May 2021 to clarify issuer accounting for modifications or exchanges of freestanding equity-classified written call options that remain equity classified after modification or exchange. The ASU requires an issuer to determine the accounting for the modification or exchange based on the economic substance of the modification or exchange. ASU 2021-04 is effective January 1, 2022 and should be applied prospectively. The adoption of ASU 2021-04 is not expected to have a material impact on our consolidated financial statements.

Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity
ASU 2020-06 was issued in August 2020 to simplify accounting for certain financial instruments. The ASU eliminates the current models that require separation of beneficial conversion and cash conversion features from convertible instruments and simplifies the derivative scope exception guidance pertaining to equity classification of contracts in an entity’s own equity. The ASU also introduces additional disclosures for convertible debt and freestanding instruments that are indexed to and settled in an entity’s own equity. The ASU amends the diluted earnings per share guidance, including the requirement to use if-converted method for all convertible instruments and an update for instruments that can be settled in either cash or shares. ASU 2020-06 is effective January 1, 2022 and should be applied on a full or modified retrospective basis. The adoption of ASU 2020-06 is not expected to have a material impact on our consolidated financial statements.

4. REVENUE

REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
Year ended December 31, 2021
(millions of Canadian dollars)       
Transportation revenue9,492 4,364 676    14,532 
Storage and other revenue147 255 246    648 
Gas gathering and processing revenue 49     49 
Gas distribution revenue  4,026    4,026 
Electricity and transmission revenue   177   177 
Total revenue from contracts with customers9,639 4,668 4,948 177   19,432 
Commodity sales    26,873  26,873 
Other revenue1,2
375 42 13 336   766 
Intersegment revenue567 1 19 (1)44 (630) 
Total revenue10,581 4,711 4,980 512 26,917 (630)47,071 

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Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
Year ended December 31, 2020
(millions of Canadian dollars)       
Transportation revenue9,161 4,523 674 — — — 14,358 
Storage and other revenue94 274 203 — — — 571 
Gas gathering and processing revenue— 27 — — — — 27 
Gas distribution revenue— — 3,663 — — — 3,663 
Electricity and transmission revenue   198 — — 198 
Total revenue from contracts with customers9,255 4,824 4,540 198 — — 18,817 
Commodity sales— — — — 19,259 — 19,259 
Other revenue1,2
584 44 17 389 — (23)1,011 
Intersegment revenue584 12 — 24 (622)— 
Total revenue10,423 4,870 4,569 587 19,283 (645)39,087 

Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
Year ended December 31, 2019
(millions of Canadian dollars)       
Transportation revenue9,082 4,477 743 — — — 14,302 
Storage and other revenue109 268 201 — — — 578 
Gas gathering and processing revenue— 423 — — — — 423 
Gas distribution revenue— — 4,210 — — — 4,210 
Electricity and transmission revenue— — — 180 — — 180 
Commodity sales— — — — — 
Total revenue from contracts with customers9,191 5,172 5,154 180 — — 19,697 
Commodity sales— — — — 29,305 — 29,305 
Other revenue1,2
659 30 387 (2)(16)1,067 
Intersegment revenue369 16 — 71 (461)— 
Total revenue10,219 5,207 5,179 567 29,374 (477)50,069 
1     Includes mark-to-market gains from our hedging program for the year ended December 31, 2021 of $59 million, (2020 - $265 million, 2019 - $346 million).
2     Includes revenues from lease contracts. Refer to Note 27 - Leases.

We disaggregate revenue into categories which represent our principal performance obligations within each business segment. These revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.

Contract Balances
Contract ReceivablesContract AssetsContract Liabilities
(millions of Canadian dollars)
Balance as at December 31, 20212,369 213 1,898 
Balance as at December 31, 20202,042 226 1,815 

Contract receivables represent the amount of receivables derived from contracts with customers.

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Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional.

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the year ended December 31, 2021 included in contract liabilities at the beginning of the period is $305 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2021 were $397 million.

Performance Obligations

SegmentNature of Performance Obligation
Liquids Pipelines
Transportation and storage of crude oil and natural gas liquids (NGLs)
Gas Transmission and Midstream
Transportation, storage, gathering, compression and treating of natural gas
Transportation of NGLs
Sale of crude oil, natural gas and NGLs
Gas Distribution and Storage
Supply and delivery of natural gas
Transportation of natural gas
Storage of natural gas
Renewable Power Generation
Generation and transmission of electricity
Delivery of electricity from renewable energy generation facilities

There was no material revenue recognized in the year ended December 31, 2021 from performance obligations satisfied in previous periods.

Payment Terms
Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution and Storage customers are received on a continuous basis based on established billing cycles.

Certain contracts in the US offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs are recorded as contract liabilities. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives.

Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is $59.8 billion, of which $7.4 billion is expected to be recognized during the year ended December 31, 2022.

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The revenues excluded from the amounts above based on optional exemptions available under ASC 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts of revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.

SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE
Long-Term Transportation Agreements
For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed.

Variable Consideration
Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes are sold or transported and actual tolls and prices are determined.

During the year ended December 31, 2021, revenue for the Canadian Mainline has been recognized in accordance with the terms of the Competitive Tolling Settlement (CTS), which expired on June 30, 2021. The tolls in place on June 30, 2021 continue on an interim basis until a new commercial arrangement is implemented and are subject to finalization and adjustment applicable to the interim period, if any. Due to the uncertainty of adjustment to tolling pursuant to a CER decision and potential customer negotiations, interim toll revenue recognized during the year ended December 31, 2021 is considered variable consideration.

Recognition and Measurement of Revenue
Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationConsolidated
Year ended December 31, 2021
(millions of Canadian dollars)    
Revenue from products transferred at a point in time  70  70 
Revenue from products and services transferred over time1
9,639 4,668 4,878 177 19,362 
Total revenue from contracts with customers9,639 4,668 4,948 177 19,432 
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Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationConsolidated
Year ended December 31, 2020
(millions of Canadian dollars)    
Revenue from products transferred at a point in time— — 60 — 60 
Revenue from products and services transferred over time1
9,255 4,824 4,480 198 18,757 
Total revenue from contracts with customers9,255 4,824 4,540 198 18,817 
Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationConsolidated
Year ended December 31, 2019
(millions of Canadian dollars)    
Revenue from products transferred at a point in time— 65 — 69 
Revenue from products and services transferred over time1
9,191 5,168 5,089 180 19,628 
Total revenue from contracts with customers9,191 5,172 5,154 180 19,697 
1Revenue 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.

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5.  SEGMENTED INFORMATION
Segmented information for the years ended December 31, 2021, 2020 and 2019 is as follows:
Year ended December 31, 2021Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
(millions of Canadian dollars)       
Revenues10,581 4,711 4,980 512 26,917 (630)47,071 
Commodity and gas distribution costs(25) (2,147) (27,174)644 (28,702)
Operating and administrative(3,431)(1,877)(1,143)(180)(48)(33)(6,712)
Income/(loss) from equity investments759 813 42 101  (4)1,711 
Impairment of equity investments (111)    (111)
Other income/(expense)13 135 385 75 (8)379 979 
Earnings/(loss) before interest, income tax expense and depreciation and amortization7,897 3,671 2,117 508 (313)356 14,236 
Depreciation and amortization(3,852)
Interest expense      (2,655)
Income tax expense      (1,415)
Earnings      6,314 
Capital expenditures1
4,051 2,420 1,343 16 1 54 7,885 
Total property, plant and equipment, net52,530 27,028 16,904 3,315 23 267 100,067 
Year ended December 31, 2020Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
(millions of Canadian dollars)       
Revenues10,423 4,870 4,569 587 19,283 (645)39,087 
Commodity and gas distribution costs(20)— (1,810)(2)(19,450)613 (20,669)
Operating and administrative(3,331)(1,859)(1,091)(191)(67)(210)(6,749)
Income/(loss) from equity investments558 479 94 (3)(1)1,136 
Impairment of equity investments— (2,351)— — — — (2,351)
Other income/(expense)53 (52)71 35 130 238 
Earnings/(loss) before interest, income tax expense and depreciation and amortization7,683 1,087 1,748 523 (236)(113)10,692 
Depreciation and amortization(3,712)
Interest expense      (2,790)
Income tax expense      (774)
Earnings      3,416 
Capital expenditures1
2,033 2,130 1,134 81 90 5,470 
Total property, plant and equipment, net48,799 25,745 16,079 3,495 24 429 94,571 

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Year ended December 31, 2019Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
(millions of Canadian dollars)       
Revenues10,219 5,207 5,179 567 29,374 (477)50,069 
Commodity and gas distribution costs(29)— (2,354)(2)(29,091)472 (31,004)
Operating and administrative(3,298)(2,232)(1,149)(189)(44)(79)(6,991)
Impairment of long-lived assets(21)(105)— (297)— — (423)
Income/(loss) from equity investments780 682 31 (2)1,503 
Other income/(expense)30 (181)67 515 435 
Earnings before interest, income tax expense and depreciation and amortization7,681 3,371 1,747 111 250 429 13,589 
Depreciation and amortization(3,391)
Interest expense(2,663)
Income tax expense(1,708)
Earnings5,827 
Capital expenditures1
2,548 1,753 1,100 23 124 5,550 
Total property, plant and equipment, net48,783 25,268 15,622 3,658 24 368 93,723 
1Includes 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 31,202120202019
(millions of Canadian dollars)   
Canada20,474 16,453 19,954 
US26,597 22,634 30,115 
 47,071 39,087 50,069 
1Revenues are based on the country of origin of the product or service sold.
Property, Plant and Equipment1
December 31,20212020
(millions of Canadian dollars)  
Canada47,102 46,499 
US52,965 48,072 
 100,067 94,571 
1Amounts are based on the location where the assets are held.

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6.  EARNINGS PER COMMON SHARE

BASIC
Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of approximately 2 million as at December 31, 2021, 5 million as at December 31, 2020, and 6 million as at December 31, 2019, resulting from our reciprocal investment in Noverco. On December 30, 2021, we closed the sale of our non-operating minority ownership of Noverco. Refer to Note 13 - Long-term Investments for more information.

DILUTED
The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period.

Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:
December 31,202120202019
(number of shares in millions)   
Weighted average shares outstanding2,023 2,020 2,017 
Effect of dilutive options2 
Diluted weighted average shares outstanding2,025 2,021 2,020 
For the years ended December 31, 2021, 2020 and 2019, 18.6 million, 29.8 million and 17.8 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $52.89, $51.42 and $53.56, respectively, were excluded from the diluted earnings per common share calculation.

7. REGULATORY MATTERS

We record assets and liabilities that result from regulated ratemaking processes that would not be recorded under US GAAP for non-regulated entities. See Note 2 - Significant Accounting Policies for further discussion. Our significant regulated businesses and the related accounting impacts are described below.

Under the current authorized rate structure for certain operations, income tax costs are recovered in rates based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of temporary differences that created the deferred income taxes, it is expected that rates will be adjusted to recover these taxes. Since most of these temporary differences are related to property, plant and equipment costs, this recovery is expected to occur over the life of the related assets.

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LIQUIDS PIPELINES
Canadian Mainline
Canadian Mainline includes the Canadian portion of our mainline system and is subject to regulation by the CER. Tolls, excluding Lines 8 and 9, are governed by the 10-year CTS which expired on June 30, 2021 (Note 4).The CTS established a Canadian Local Toll for unusual,all volumes shipped on the Canadian Mainline and an International Joint Tariff for all volumes shipped from western Canadian receipt points to delivery points on our Lakehead System. Under the CTS, we have recognized a regulatory asset of $2.1 billion as at December 31, 2021 (2020 - $1.9 billion) to offset deferred income taxes, as a CER rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the CTS.
non-recurring
or
non-operatingSouthern Lights Pipeline
factors. Management
The US and Canadian portions of the Southern Lights Pipeline are regulated by the FERC and CER, respectively. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost-of-service toll methodology. Toll adjustments are filed annually with the regulators and provide for the recovery of allowable operating and debt financing costs, plus a pre-determined after-tax return on equity (ROE) of 10%.

GAS TRANSMISSION AND MIDSTREAM
British Columbia Pipeline and Maritimes & Northeast Canada
British Columbia (BC) Pipeline and Maritimes & Northeast (M&N) Canada are regulated by the CER. Rates are approved by the CER through negotiated toll settlement agreements based on cost-of-service. Both our BC Pipeline and M&N Canada systems operate under the terms of their respective negotiated toll settlements, which stipulate an allowable ROE and the continuation and establishment of certain deferral and variance accounts. As both settlement agreements expired in December 2021, we are currently operating under CER-approved interim tolls and negotiating the terms of new toll settlements for periods beginning in 2022.

US Gas Transmission
Most of our US gas transmission and storage services are regulated by the FERC and may also uses DCFbe subject to assess the jurisdiction of various other federal, state and local agencies. The FERC regulates natural gas transmission in US interstate commerce including the establishment of rates for services, while rates for intrastate commerce and/or gathering services are regulated by the state gas commissions. Cost-of-service is the basis for the calculation of regulated tariff rates, although the FERC also allows the use of negotiated and discounted rates within contracts with shippers that may result in a rate that is above or below the FERC-regulated recourse rate for that service.

GAS DISTRIBUTION AND STORAGE
Enbridge Gas
Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year Incentive Regulation (IR) framework using a price cap mechanism. The price cap mechanism establishes new rates each year through an annual base rate escalation at inflation less a 0.3% stretch factor, annual updates for certain costs to be passed through to customers, and where applicable, the recovery of material discrete incremental capital investments beyond those that can be funded through base rates. The IR framework includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved ROE.

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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 31,20212020Recovery/Refund
Period Ends
(millions of Canadian dollars)
Current regulatory assets
   Under-recovery of fuel costs114 86 2022
   Other current regulatory assets145 146 2022
Total current regulatory assets1 (Note 9)
259 232 
Long-term regulatory assets
   Deferred income taxes2
4,176 3,890 Various
   Long-term debt3
398 429 2023-2046
Negative salvage4
243 246 Various
   Purchase gas variance215 — 2023
   Accounting policy changes5
157 169 Various
   Pension plan receivable6
78 402 Various
   Other long-term regulatory assets339 261 Various
Total long-term regulatory assets1
5,606 5,397 
Total regulatory assets5,865 5,629 
Current regulatory liabilities
   Purchase gas variance 153 2021
   Other current regulatory liabilities106 117 2022
Total current regulatory liabilities7
106 270 
Long-term regulatory liabilities
   Future removal and site restoration reserves8
1,543 1,455 Various
   Regulatory liability related to US income taxes9
895 941 2050-2072
   Pipeline future abandonment costs (Note 14)
649 578 Various
   Other long-term regulatory liabilities234 150 Various
Total long-term regulatory liabilities7
3,321 3,124 
Total regulatory liabilities3,427 3,394 

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 reflects unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited, relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and recovered in rates, as previously approved by the OEB.
6 Represents the regulatory offset to our pension liability to the extent that it is expected to be included in regulator-approved future rates and recovered from customers. The settlement period for this balance is not determinable. In the absence of rate-regulated accounting, this regulatory balance and the related pension expense would be recorded in earnings and OCI.
7 Current regulatory liabilities are included in Accounts payable and other, while long-term regulatory liabilities are included in Other long-term liabilities.
8 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the OEB, to fund future costs of removal and site restoration relating to property, plant and equipment. These costs are collected as part of the depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance will occur over the long-term as costs are incurred. In the absence of rate-regulated accounting, depreciation rates would not include a charge for removal and site restoration and costs would be charged to earnings as incurred with recognition of revenue for amounts previously collected.
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9 The regulatory liability related to US income taxes resulted from the US tax reform legislation dated December 22, 2017. These balances will be refunded to customers in accordance with the respective rate settlements approved by the FERC.

8.  ACQUISITIONS AND DISPOSITIONS

ACQUISITION
Moda Midstream Operating, LLC
On October 12, 2021, through a wholly-owned US subsidiary, we acquired all of the outstanding membership interests in Moda for $3.7 billion (US$3.0 billion) of cash plus potential contingent payments of up to US$150 million dependent on performance of the companyassets (the Acquisition). The Acquisition is also subject to customary closing and working capital adjustments. Moda owns and operates a light crude export platform with very large crude carrier capability. The Acquisition aligns with and advances our US Gulf Coast export strategy and enables connectivity to low-cost and long-lived reserves in the Permian and Eagle Ford basins.

We accounted for the Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations. In accordance with valuation methodologies described in ASC 820 Fair Value Measurements, the acquired assets and assumed liabilities were recorded at their estimated fair values as at the date of acquisition.

The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Moda:
October 12, 2021
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets62
Property, plant and equipment (a)1,480
Long-term investments (b)427
Intangible assets (c)1,781
Current liabilities59
Long-term liabilities17
Goodwill (d)268
Purchase price:
Cash3,755
Contingent consideration (e)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.

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c) Intangible assets consist primarily of customer relationships associated with long-term take-or-pay contracts. Fair value was determined using an income-based approach by estimating the present value of the after-tax earnings attributable to the contracts, including earnings associated with expected renewal terms, and will be amortized on a straight-line basis over an expected useful life of 10 years.

d) Goodwill is primarily attributable to uncontracted future revenues, existing assembled assets that cannot be duplicated at the same cost by a new entrant, and enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. The goodwill balance recognized has been assigned to our Liquids Pipelines segment and is tax deductible over 15 years.

e) We agreed to pay additional contingent consideration of up to US$150 million to Moda's former membership interest holders if Moda's monthly volumes of crude oil loaded onto a vessel equal or exceed specified throughput levels. These performance requirements terminate the earlier of December 31, 2023 or the date the final contingent payment is made. The US$150 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition. As at December 31, 2021, there were no changes to the amount of contingent consideration recognized.

Acquisition-related expenses incurred were approximately $21 million for the year ended December 31, 2021 and are included in Operating and administrative expense in the Consolidated Statements of Earnings.

Upon completion of the Acquisition, we began consolidating Moda. For the period beginning October 12, 2021 through to December 31, 2021, Moda generated approximately $80 million in operating revenues and $9 million in earnings attributable to common shareholders.

Our supplemental pro forma consolidated financial information for the years ended December 31, 2021 and 2020, including the results of operations for Moda as if the Acquisition had been completed on January 1, 2020, are as follows:

Year ended December 31,20212020
(unaudited; millions of Canadian dollars)
Operating revenues47,339 39,435 
Earnings attributable to common shareholders1,2
5,771 2,938 
1 Acquisition-related expenses of $21 million (after-tax $16 million) were excluded from earnings attributable to common shareholders for the year ended December 31 2021 and deducted for the year ended December 31, 2020.
2 Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets of $193 million and $207 million (after-tax of $145 million and $155 million) for the years ended December 31, 2021 and 2020, respectively.

DISPOSITIONS
Line 10 Crude Oil Pipeline
In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. (EEP), owned the Canadian and US portions of Line 10, respectively, and the related assets were included in our Liquids Pipelines segment. The transaction closed on June 1, 2020. No gain or loss on disposition was recorded.

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Montana-Alberta Tie Line
In the fourth quarter of 2019, we committed to a plan to sell the Montana-Alberta Tie Line (MATL) transmission asset, a 345 kilometer transmission line from Great Falls, Montana to Lethbridge, Alberta. MATL was included in our Renewable Power Generation segment. The purchase and sale agreement was signed in January 2020.

Upon the reclassification and subsequent remeasurement of MATL assets as held for sale, a loss of $297 million was included within Impairment of long-lived assets in the Consolidated Statements of Earnings for the year ended December 31, 2019.

On May 1, 2020, we closed the sale of MATL for cash proceeds of approximately $189 million. After closing adjustments, a gain on disposal of $4 million was included in Other income/(expense) in the Consolidated Statements of Earnings.

Ozark Gas Transmission
In the first quarter of 2020, we agreed to sell our Ozark Gas Transmission and Ozark Gas Gathering assets (Ozark assets). The Ozark assets are composed of a transmission system that extends from southeastern Oklahoma through Arkansas to southeastern Missouri, and a fee-based gathering system that accesses Fayetteville Shale and Arkoma production. These assets were included in our Gas Transmission and Midstream segment.

On April 1, 2020, we closed the sale of the Ozark assets for cash proceeds of approximately $63 million. After closing adjustments, a gain on disposal of $1 million was included in Other income/(expense) in the Consolidated Statements of Earnings.

Canadian Natural Gas Gathering and Processing Businesses
On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses to Brookfield Infrastructure Partners L.P. and its dividend payout target. DCFinstitutional partners for a cash purchase price of approximately $4.3 billion, subject to customary closing adjustments. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations (collectively, Canadian Natural Gas Gathering and Processing Businesses assets); these assets were part of our Gas Transmission and Midstream segment.

On October 1, 2018, we closed the sale of the provincially regulated facilities. On December 31, 2019, we closed the sale of the federally regulated facilities for proceeds of approximately $1.7 billion. After closing adjustments, a loss on disposal of $268 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019. As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach.

St. Lawrence Gas Company, Inc.
In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. (St. Lawrence Gas). St. Lawrence Gas assets were included in the Gas Distribution and Storage segment. On November 1, 2019, we closed the sale of St. Lawrence Gas for cash proceeds of approximately $72 million. After closing adjustments, a loss on disposal of $10 million was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019.

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Enbridge Gas New Brunswick
In December 2018, we entered into an agreement for the sale of Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB). EGNB assets were a part of our Gas Distribution and Storage segment. On October 1, 2019, we closed the sale of EGNB to Liberty Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp., for cash proceeds of approximately $331 million. After closing adjustments, a loss on disposal of $3 million was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019.

As EGNB assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As such, allocated goodwill of $133 million was included in assets subsequently disposed.

9.  ACCOUNTS RECEIVABLE AND OTHER

December 31,20212020
(millions of Canadian dollars)
Trade receivables and unbilled revenues1
4,957 3,923 
Short-term portion of derivative assets (Note 24)
529 323 
Regulatory assets (Note 7)
259 232 
Taxes receivable407 374 
Other710 406 
 6,862 5,258 
1 Net of allowance for expected credit losses of $87 million as at December 31, 2021 and $70 million as at December 31, 2020.

10.  INVENTORY
December 31,20212020
(millions of Canadian dollars)  
Natural gas953 710 
Crude oil624 744 
Other93 82 
 1,670 1,536 

11.  PROPERTY, PLANT AND EQUIPMENT
 Weighted Average  
December 31,Depreciation Rate20212020
(millions of Canadian dollars)   
Pipelines2.8 %62,997 57,459 
Facilities and equipment3.1 %34,331 30,149 
Land and right-of-way1
2.3 %3,320 2,896 
Gas mains, services and other2.7 %13,606 12,813 
Storage2.4 %3,099 2,936 
Wind turbines, solar panels and other4.0 %4,912 4,877 
Other8.2 %1,507 1,558 
Under construction— %2,268 5,762 
Total property, plant and equipment 126,040 118,450 
Total accumulated depreciation(25,973)(23,879)
Property, plant and equipment, net 100,067 94,571 
1 The measurement of weighted average depreciation rate excludes non-depreciable assets.

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Depreciation expense for the years ended December 31, 2021, 2020 and 2019 was $3.5 billion, $3.4 billion and $3.0 billion, respectively.

IMPAIRMENT
Access Northeast Project
In 2019, we announced that we terminated the agreements with Eversource Energy and National Grid USA Service Company, Inc. related to the Access Northeast project. As a result, we recognized an impairment loss of $105 million for the year ended December 31, 2019, which is included in Impairment of long-lived assets in the Consolidated Statements of Earnings. Access Northeast is part of our Gas Transmission and Midstream segment.

Impairment charges were based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash flows.

12.  VARIABLE INTEREST ENTITIES
CONSOLIDATED VARIABLE INTEREST ENTITIES
Our consolidated VIEs consist of legal entities where we are the primary beneficiary. We are the primary beneficiary when our variable interest(s) provide us with (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. We determine whether we are the primary beneficiary of a VIE by considering qualitative and quantitative factors, including, but not limited to: decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties.

The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.
December 31,
20211
20201
(millions of Canadian dollars)  
Assets  
Cash and cash equivalents247 215 
Restricted cash4 
Accounts receivable and other99 65 
Inventory9 
 359 288 
Property, plant and equipment, net3,052 3,201 
Long-term investments16 14 
Restricted long-term investments101 84 
Deferred amounts and other assets2 
Intangible assets, net108 115 
 3,638 3,705 
Liabilities  
Accounts payable and other84 52 
Other long-term liabilities182 175 
Deferred income taxes5 
 271 232 
3,367 3,473 
1 Excludes assets and liabilities of EEP and Spectra Energy Partners, L.P. (SEP) following the subsidiary guarantees agreement entered on January 22, 2019. See Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Summarized Financial Information.
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We do not have obligations to provide additional financial support to any of our consolidated VIEs.
UNCONSOLIDATED VARIABLE INTEREST ENTITIES
We currently hold interests in several non-consolidated VIEs where we are not the primary beneficiary as we do not have the power to direct the activities of the VIEs that most significantly impact the VIEs' economic performance. These interests include investments in limited partnerships that are assessed to be VIEs due to the limited partners not having substantive kick-out rights or participating rights. The power to direct the activities of a majority of these non-consolidated limited partnership VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee that makes significant decisions for the VIE and none of the partners may make significant decisions unilaterally.

The carrying amount of these VIEs and our estimated maximum exposure to loss as at December 31, 2021 and 2020 are presented below:
Carrying
Amount of

Maximum
Exposure to
December 31, 2021the VIELoss
(millions of Canadian dollars)  
Aux Sable Liquid Products L.P.1
113 195 
EIH S.á r.l.2, 8
38 664 
Enbridge Renewable Infrastructure Investments S.á r.l.3
54 2,121 
Rampion Offshore Wind Limited5
450 508 
Vector Pipeline L.P.6
189 374 
Other4,7
210 426 
 1,054 4,288 
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Carrying
Amount of

Maximum
Exposure to
December 31, 2020the VIELoss
(millions of Canadian dollars)  
Aux Sable Liquid Products L.P.1
106 187 
Éolien Maritime France SAS2, 8
96 949 
Enbridge Renewable Infrastructure Investments S.á r.l.3
100 2,516 
PennEast Pipeline Company, LLC4
116 371 
Rampion Offshore Wind Limited5
599 650 
Vector Pipeline L.P.6
201 390 
Other7
133 361 
1,351 5,424 
1At December 31, 2021 and 2020, the maximum exposure to loss includes guarantees by us for our respective share of the VIE’s borrowing on a bank credit facility.
2At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the three French offshore wind projects for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $73 million held by us as at December 31, 2021. On March 18, 2021, Enbridge Renewable Infrastructure Holdings S.á r.l. (ERIH) closed the sale of 49% of its interest in EIH S.á r.l. to the Canada Pension Plan Investment Board (CPP Investments).
3At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $807 million and $904 million held by us as at December 31, 2021 and 2020, respectively.
4At December 31, 2021, the maximum exposure to loss is limited to our equity investment and at December 31, 2020, the maximum exposure to loss includes the remaining expected contributions to the joint venture.
5At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in project contracts in which we would be liable for in the event of default by the VIE.
6At December 31, 2021 and 2020, the maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable for $80 million and $84 million held by us as at December 31, 2021 and 2020, respectively, and an outstanding credit facility for $105 million as at December 31, 2021 and 2020.
7At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE.
8At December 31, 2020, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $132 million held by us as at December 31, 2020. In relation to the sale of 49% of EIH S.á r.l.'s interest to CPP Investments, Eolien Maritime France SAS is now reported under EIH S.á r.l. in 2021.

We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2021 and 2020.

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13.  LONG-TERM INVESTMENTS
 Ownership  
December 31,Interest20212020
(millions of Canadian dollars)   
EQUITY INVESTMENTS   
Liquids Pipelines   
MarEn Bakken Company LLC1
75.0 %1,728 1,795 
Gray Oak Holdings LLC2
35.0 %469 502 
Seaway Crude Holdings LLC50.0 %2,634 2,668 
Illinois Extension Pipeline Company, L.L.C.3
65.0 %593 623 
Cactus II Pipeline, LLC4
20.0 %434 — 
Other30.0% - 43.8%71 73 
Gas Transmission and Midstream
Alliance Pipeline5
50.0 %504 269 
Aux Sable6
42.7% - 50.0%238 251 
DCP Midstream, LLC7
50.0 %397 331 
Gulfstream Natural Gas System, L.L.C.50.0 %1,180 1,175 
Nexus Gas Transmission, LLC50.0 %1,724 1,745 
PennEast Pipeline Company, LLC20.0 %12 116 
Sabal Trail Transmission, LLC50.0 %1,464 1,510 
Southeast Supply Header, LLC50.0 %82 84 
Steckman Ridge, LP50.0 %88 90 
Vector Pipeline8
60.0 %189 201 
Offshore - various joint ventures22.0% - 74.3%309 338 
Other33.3%2 
Gas Distribution and Storage
Noverco Common Shares9
38.9 % 156 
Other47.6% - 50%20 13 
Renewable Power Generation
EIH S.a.r.l.10
51.0 %38 96 
Enbridge Renewable Infrastructure Investments S.a.r.l.51.0 %54 100 
Rampion Offshore Wind Limited24.9 %450 599 
NextBridge Infrastructure LP25.0 %186 122 
Other12.0% - 50.0%93 74 
Eliminations and Other
Other42.7% - 50.0%23 32 
OTHER LONG-TERM INVESTMENTS
Gas Distribution and Storage
Noverco Preferred Shares9
 567 
Renewable Power Generation
Emerging Technologies and Other32 32 
Eliminations and Other
Other11
310 252 
  13,324 13,818 
1Owns 49% interest in Bakken Pipeline Investments L.L.C., which owns 75% of the Bakken Pipeline System resulting in a 27.6% effective interest in the Bakken Pipeline System.
2Owns 65% interest in Gray Oak Pipeline, LLC resulting in a 22.8% effective interest in Gray Oak Pipeline, LLC.
3Owns the Southern Access Extension Project.
4In October 2021 we acquired an effective 20.0% interest in Cactus II Pipeline, LLC through the acquisition of Moda Midstream Operating, LLC. See Note 8 - Acquisitions and Dispositions for further discussion.
5Includes Alliance Pipeline Limited Partnership in Canada and Alliance Pipeline L.P. in the US.
6Includes Aux Sable Canada LP in Canada and Aux Sable Liquid Products LP and Aux Sable Midstream LLC in the US.
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7Our ownership in DCP Midstream, LLC (DCP Midstream) holds an interest of 56.5% in DCP Midstream, LP.
8Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US.
9On December 30, 2021, we sold our 38.9% common share and preferred share interest of Noverco Inc.
10 On March 18, 2021, we sold 49% of EIH S.a.r.l., an entity that holds our 50% interest in Éolien Maritime France SAS (EMF), to the CPP Investments. This resulted in a 25.5% effective interest in EMF. Through our investment in EMF, we own equity interests in three French offshore wind projects, including Saint-Nazaire (25.5%), Fécamp (17.9%) and Calvados (21.7%).
11 Includes investments held and valued at fair value through net income.

Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees' assets at the purchase date. As at December 31, 2021, this basis difference was $2.5 billion (2020 - $2.4 billion), of which $730 million (2020 - $657 million) was amortizable.

For the years ended December 31, 2021, 2020 and 2019, distributions received from equity investments were $2.2 billion, $2.1 billion and $2.2 billion, respectively.

Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows:
Year ended December 31,202120202019
(millions of Canadian dollars)
Operating revenues19,891 13,987 15,687 
Operating expenses16,514 12,223 13,153 
Earnings2,952 2,306 3,016 
Earnings attributable to Enbridge1,711 1,136 1,503 
December 31,20212020
(millions of Canadian dollars)
Current assets3,581 3,136 
Non-current assets44,497 45,955 
Current liabilities3,678 3,539 
Non-current liabilities16,950 19,639 
Noncontrolling interests3,786 3,810 
Noverco Inc.
On June 7, 2021, IPL System Inc., a wholly owned subsidiary of Enbridge, entered into a purchase and sale agreement to sell its 38.9% common share and preferred share interest in Noverco to Trencap L.P. for $1.1 billion in cash.

On December 30, 2021, we closed the sale of Noverco for cash proceeds of $1.1 billion. After closing adjustments, a gain on disposal of $303 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2021. Noverco was previously included in our Gas Distribution and Storage segment.

IMPAIRMENT OF EQUITY INVESTMENTS
PennEast Pipeline Company, LLC
PennEast Pipeline Company, LLC (PennEast) is a joint venture formed to develop a natural gas transmission pipeline to serve local distribution companies and power generators in Southeastern Pennsylvania and New Jersey, is owned 20% by Enbridge, and is recorded as an equity method investment. In the third quarter of 2021, PennEast determined further development of the project was no longer viable and development of the project was ceased. As a result, we recorded an other-than-temporary impairment loss of $111 million on our investment for the year ended December 31, 2021 based on the estimated fair value of our share of the net assets. The carrying value of this investment as at December 31, 2021 and 2020 was $12 million and $116 million, respectively.

134


Steckman Ridge, LP
Steckman Ridge, LP (Steckman Ridge) is engaged in the storage of natural gas, is owned 50% by Enbridge and is recorded as an equity method investment. During the year ended December 31, 2020, Steckman Ridge’s forecasted performance was adjusted for the expectation that future available capacity will be re-contracted at lower than expected rates and an other than temporary impairment loss on our investment of $221 million for the year ended December 31, 2020 has been converted to DCF per share by taking DCFwas recorded based on a discounted cash flow analysis. The carrying value of C$9,440this investment as at December 31, 2021 and 2020 was $88 million and dividing$90 million, respectively.

Southeast Supply Header, L.L.C.
Southeast Supply Header, L.L.C. (SESH) provides natural gas transmission services from east Texas and northern Louisiana to the southeast markets of the Gulf Coast. SESH is owned 50% by 2,020Enbridge and is recorded as an equity method investment. The forecasted performance of SESH was revised during the year ended December 31, 2020 to reflect downward revisions to future negotiated rates as well as higher than expected available capacity levels, caused primarily by a significant contract expiry. An other than temporary impairment loss on our investment of $394 million for the weighted average numberyear ended December 31, 2020 was recorded based on a discounted cash flow analysis. The carrying value of this investment as at December 31, 2021 and 2020 was $82 million and $84 million, respectively.

DCP Midstream, LLC
DCP Midstream, a 50% owned equity method investment of Enbridge, shares outstanding asholds an equity interest in DCP Midstream, LP. A decline in the market price of DCP Midstream, LP’s publicly traded units during the first quarter of 2020 resulted in an other than temporary impairment loss on our investment in DCP Midstream of $1.7 billion for the year ended December 31, 2020. For purposesIn addition, we incurred losses of $324 million through our equity earnings pick up in relation to asset and goodwill impairment losses recorded by DCP Midstream, LP. The carrying value of our investment in DCP Midstream as at December 31, 2021 and 2020 was $397 million and $331 million, respectively.

Our investments in PennEast, Steckman, SESH and DCP Midstream form part of our Gas Transmission and Midstream segment. The impairment losses were recorded within Impairment of Equity Investments in the Consolidated Statements of Earnings.

14.  RESTRICTED LONG-TERM INVESTMENTS
Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline abandonment costs for all CER regulated pipelines as a result of the CER’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues on the Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term liabilities on the Consolidated Statements of Financial Position.

135


We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money market securities in the US and Canada.

As at December 31, 2021 and 2020, STIP award determinationswe had restricted long-term investments held in trust and classified as described on page 26, DCF was converted to DCF per share by taking DCFavailable-for-sale of C$9,473$630 million and dividing$553 million, respectively. The cost basis of our debt securities classified as available-for-sale and recorded as part of our restricted long-term investment balance was $383 million and $322 million as at December 31, 2021 and 2020, respectively. Within Other long-term liabilities we had estimated future abandonment costs related to LMCI of $649 million and $578 million as at December 31, 2021 and 2020, respectively (Note 7).

15.  INTANGIBLE ASSETS
 Weighted Average Accumulated 
December 31, 2021Amortization RateCost AmortizationNet
(millions of Canadian dollars)    
Software12.0 %2,067 (1,148)919 
Power purchase agreements4.5 %63 (21)42 
Project agreement1
4.0 %152 (27)125 
Customer relationships8.5 %2,532 (215)2,317 
Other intangible assets3.9 %475 (116)359 
Under development— %246  246 
  5,535 (1,527)4,008 

 Weighted Average Accumulated 
December 31, 2020Amortization RateCost AmortizationNet
(millions of Canadian dollars)    
Software10.5 %2,043 (1,299)744 
Power purchase agreements4.5 %63 (18)45 
Project agreement1
4.0 %153 (21)132 
Customer relationships5.0 %724 (139)585 
Other intangible assets2.7 %456 (96)360 
Under development— %214 — 214 
  3,653 (1,573)2,080 
1Represents a project agreement acquired from the merger of Enbridge and Spectra Energy.

For the years ended December 31, 2021, 2020 and 2019, our amortization expense related to intangible assets totaled $348 million, $294 million and $296 million, respectively. Our expected amortization expense associated with existing intangible assets for each of the years 2022 to 2026 is $492 million.

136


16.  GOODWILL
Liquids
Pipelines
Gas
Transmission and Midstream
Gas
Distribution and Storage
Energy
Services
Consolidated
(millions of Canadian dollars)
Balance at January 1, 20207,951 19,844 5,356 33,153 
Foreign exchange and other(123)(364)— — (487)
Acquisition— — 22 — 22 
Balance at December 31, 20201,2
7,828 19,480 5,378 32,688 
Foreign exchange and other(55)(145)  (200)
Acquisition3
268  19  287 
Balance at December 31, 20211,2
8,041 19,335 5,397 2 32,775 
1 Gross cost of goodwill as at December 31, 2021 and 2020 was $34.4 billion and $34.3 billion, respectively.
2 Accumulated impairment as at December 31, 2021 and 2020 was $1.6 billion.
3 In 2021, we recorded $268 million of goodwill related to the acquisition of Moda. See Note 8 - Acquisitions and Dispositions for further discussion.

17.  ACCOUNTS PAYABLE AND OTHER

December 31,20212020
(millions of Canadian dollars)
Trade payables and operating accrued liabilities4,470 3,497 
Dividends payable1,773 1,728 
Current deferred credits853 978 
Construction payables and contractor holdbacks844 855 
Current derivative liabilities (Note 24)
717 896 
Taxes payable478 622 
Other632 652 
9,767 9,228 

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18.  DEBT
December 31,
Weighted Average Interest Rate9
Maturity20212020
(millions of Canadian dollars)    
Enbridge Inc.    
US dollar senior notes3.2 %2022 - 205110,992 8,536 
Medium-term notes3.9 %2022 - 20648,123 8,323 
Sustainability-linked bonds1.1 %20332,363 — 
Fixed-to-fixed subordinated term notes1
5.8 %20801,263 1,274 
Fixed-to-floating rate subordinated term notes2
5.8 %2023 - 20286,442 6,477 
Floating rate notes3
02022 - 20231,579 956 
Commercial paper and credit facility draws1.0 %2022 - 20267,837 8,719 
Other4
5 
Enbridge (U.S.) Inc.
Commercial paper and credit facility draws0.4 %2023 - 20264,845 492 
Other4
7 
Enbridge Energy Partners, L.P.
Senior notes6.5 %2025 - 20453,095 3,886 
Enbridge Gas Inc.
Medium-term notes3.8 %2022 - 20519,010 8,485 
Debentures9.1 %2024 - 2025210 210 
Commercial paper and credit facility draws0.5 %20231,515 1,121 
Enbridge Pipelines (Southern Lights) L.L.C.
Senior notes4.0 %2040949 1,038 
Enbridge Pipelines Inc.
Medium-term notes5
4.0 %2022 - 20515,575 4,775 
Debentures8.2 %2024200 200 
Commercial paper and credit facility draws0.7 %2023667 1,278 
Enbridge Southern Lights LP
Senior notes4.0 %2040240 257 
Spectra Energy Capital, LLC
Senior notes7.0 %2032 - 2038218 220 
Spectra Energy Partners, LP
Senior notes3.9 %2022 - 20488,451 8,332 
Westcoast Energy Inc.
Medium-term notes4.5 %2022 - 20411,475 1,625 
Debentures8.1 %2025 - 2026275 275 
Fair value adjustment667 750 
Other6
(363)(344)
Total debt7
  75,640 66,897 
Current maturities  (6,164)(2,957)
Short-term borrowings8
  (1,515)(1,121)
Long-term debt  67,961 62,819 
1For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be set to equal to the Five-Year US Treasury Rate plus a margin of 5.31% from years 10 to 30 and a margin of 6.06% from years 30 to 60.
2For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal to the Canadian Dollar Offered Rate (CDOR) or the London Interbank Offered Rate (LIBOR) plus a margin. The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events.
3The notes carry an interest rate equal to the three-month LIBOR plus a margin of 50 basis points and Secured Overnight Financing Rate (SOFR) plus a margin of 40 basis points.
4Primarily finance lease obligations.
5Included in medium-term notes is $100 million with a maturity date of 2112.
6Primarily unamortized discounts, premiums and debt issuance costs.
72021 - $36 billion and US$31 billion; 2020 - $35 billion and US$24 billion. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment.
8Weighted average interest rates on outstanding commercial paper were 0.5% as at December 31, 2021 (2020 - 0.3%).
9Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2021.

As at December 31, 2021, all outstanding debt was unsecured.

138


CREDIT FACILITIES
The following table provides details of our committed credit facilities as at December 31, 2021:
Maturity1
Total Facilities
Draws2
Available
(millions of Canadian dollars)    
Enbridge Inc.2022-20269,137 7,837 1,300 
Enbridge (U.S.) Inc.2023-20266,948 4,845 2,103 
Enbridge Pipelines Inc.20233,000 667 2,333 
Enbridge Gas Inc.20232,000 1,515 485 
Total committed credit facilities 21,085 14,864 6,221 
1Maturity date is inclusive of the one-year term out option for certain credit facilities.
2Includes facility draws and commercial paper issuances that are back-stopped by 2,020credit facilities.

On February 10, 2021, Enbridge Inc. entered into a three year, revolving, extendible, sustainability-linked credit facility for $1.0 billion with a syndicate of lenders and concurrently terminated our one year, revolving, syndicated credit facility for $3.0 billion.

On February 25, 2021, two term loans with an aggregate total of US$500 million were repaid with proceeds from a floating rate notes issuance.

On July 22 and 23, 2021, we renewed approximately $8.0 billion of our five-year credit facilities, extending the maturity date out to July 2026. We also extended approximately $10.0 billion of our 364-day extendible credit facilities to July 2022, which includes a one-year term out provision to July 2023.

On February 10, 2022 we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025.

In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $854 million was unutilized as at December 31, 2021. As at December 31, 2020, we had $849 million of uncommitted demand letter of credit facilities, of which $533 million was unutilized.

Our credit facilities carry a weighted average numberstandby fee of Enbridge shares outstanding0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as ofa back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2022 to 2026.

As at December 31, 2020. For purposes2021 and 2020, commercial paper and credit facility draws, net of 2018 PSU payout determinationsshort-term borrowings and non-revolving credit facilities that mature within one year, of $11.3 billion and $9.9 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as described on page 31, DCF was converted to DCF per share by taking DCF of C$9,848 million and dividing by 2,020 million,long-term debt.

139


LONG-TERM DEBT ISSUANCES
During the weighted average number of Enbridge shares outstanding as ofyear ended December 31, 2020.
2021, we completed the following long-term debt issuances totaling US$3.9 billion and $3.2 billion:
CompanyIssue DatePrincipal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
February 2021
Year ended December 31, 2020
Floating rate senior-notes due February 20231
US$500
June 20212.50% Sustainability-linked senior notes due August 2033US$1,000
June 20213.40% senior notes due August 2051US$500
September 20213.10% Sustainability-linked medium-term notes due September 2033$1,100
September 20214.10% medium-term notes due September 2051$400
October 20210.55% senior notes due October 2023US$500
October 20211.60% senior notes due October 2026US$500
October 20213.40% senior notes due August 2051US$500
Enbridge Gas Inc.
September 20212.35% medium-term notes due September 2031$475
September 20213.20% medium-term notes due September 2051$425
Enbridge Pipelines Inc.
May 20212.82% medium-term notes due May 2031$400
May 20214.20% medium-term notes due May 2051$400
Spectra Energy Partners, LP
September 2021
   (unaudited, millions of Canadian dollars)
2.50% senior notes due September 20312
US$400
1Notes carry an interest rate equal to the SOFR plus a margin of 40 basis points.
2Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.

On January 19, 2022, we closed a $750 million private placement offering of non-call 10-year fixed-to-fixed subordinated notes which mature on January 19, 2082. The net proceeds from the offering will be used to redeem the Preference Shares, Series 17 at par on March 1, 2022.

LONG-TERM DEBT REPAYMENTS
During the year ended December 31, 2021, we completed the following long-term debt repayments totaling $1.1 billion and US$914 million, respectively:
CompanyRepayment DatePrincipal Amount
(millions of Canadian dollars unless otherwise stated)
   Cash provided by operating activities
Enbridge Inc.
9,781
   Adjusted for changes in operating assets and liabilities
1
February 20214.26% medium-term notes(93$200
March 20213.16% medium-term notes$400
Enbridge Energy Partners, L.P.
June 2021
4.20% senior notes
9,688
US$600
Enbridge Gas Inc.
   Distributions to noncontrolling interests and redeemable noncontrolling interests
2
May 20212.76% medium-term notes(300$200
December 20214.77% medium-term notes$175
Enbridge Pipelines (Southern Lights) L.L.C.
   Preference share dividends
June and December 20213.98% senior notes(380US$64
Enbridge Southern Lights LP
   Maintenance capital expenditures
3
June and December 20214.01% senior notes(915$16
Spectra Energy Partners, LP
   Significant adjustment items:
March 20214.60% senior notesUS$250
Westcoast Energy Inc.
Other receipts of cash not recognized in revenue
4
October 20213.88% medium-term notes292
Employee severance, transition and transformation costs
335
Distributions from equity investments in excess of cumulative earnings
2
675
Other items
45
   DCF
9,440
    Adjusting items in respect of:
For STIP calculation purposes, normalizations including (but not limited to) the net accretive impact of financing and strategic actions not contemplated at the time of target setting expressed in DCF
33
   Total DCF adjusted for 2020 STIP award determinations
9,473
   DCF
9,440
   Adjusting items in respect of:
For 2018 PSU calculation purposes, normalizations including (but not limited to) the net accretive impact of financing and strategic actions not contemplated at the time of the grant expressed in DCF
408
   Total DCF adjusted for 2018 PSU payout determinations
9,848
$150

140


DEBT COVENANTS
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2021, we were in compliance with all debt covenants.

INTEREST EXPENSE
Year ended December 31,202120202019
(millions of Canadian dollars)   
Debentures and term notes2,850 2,913 2,783 
Commercial paper and credit facility draws70 123 273 
Amortization of fair value adjustment(50)(54)(67)
Capitalized interest(215)(192)(326)
 2,655 2,790 2,663 

19.  ASSET RETIREMENT OBLIGATIONS
 
Our ARO relate mostly to the retirement of pipelines, renewable power generation assets and obligations related to right-of way agreements and contractual leases for land use.
1
Changes in operating assets and liabilities, net of recoveries.

2
Presented net of adjusting items.
The discount rates used to estimate the present value of the expected future cash flows for the year ended December 31, 2021 ranged from 0.9% to 9.0% (2020 - 1.8% to 9.0%).
3
Maintenance capital expenditures are expenditures that are required for the ongoing support and maintenance of the existing pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete or completing their useful lives). For the purpose of DCF, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets.

4
Consists of cash received net of revenue recognized for contracts under
make-up
rights and similar deferred revenue arrangements.
A reconciliation of movements in our ARO liabilities is as follows:
December 31,20212020
(millions of Canadian dollars)
Obligations at beginning of year496 520 
Liabilities disposed — 
Liabilities incurred — 
Liabilities settled(67)(30)
Change in estimate and other70 — 
Foreign currency translation adjustment(3)(6)
Accretion expense6 12 
Obligations at end of year502 496 
Presented as follows:
Accounts payable and other160 56 
Other long-term liabilities342 440 
502 496 

65
141

Table

20.  NONCONTROLLING INTERESTS
NONCONTROLLING INTERESTS
The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of ContentsFinancial Position:
December 31,20212020
(millions of Canadian dollars)
Algonquin Gas Transmission, L.L.C377 384 
Maritimes & Northeast Pipeline, L.L.C546 558 
Renewable energy assets1,503 1,646 
Westcoast Energy Inc.1
116 408 
2,542 2,996 
1Includes NaN and 12 million cumulative redeemable preferred shares as at December 31, 2021 and 2020, respectively.

Westcoast Energy Inc. Preferred Shares Redemption
On March 20, 2019, Westcoast Energy Inc. (Westcoast) exercised its right to redeem all of its outstanding 5.5% Cumulative Redeemable First Preferred Shares, Series 7 (Series 7 Shares) and all of its outstanding 5.6% Cumulative Redeemable First Preferred Shares, Series 8 (Series 8 Shares) at a price of $25 per Series 7 Share and $25 per Series 8 Share, respectively, for a total payment of $300 million. In addition, payment of $4 million was made for all accrued and unpaid dividends. As a result, we recorded a $300 million decrease in Noncontrolling interests for the year ended December 31, 2019.

On January 15, 2021, Westcoast redeemed its Cumulative Five-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 10 with a par value of $115 million. The par value of $115 million was included in Accounts payable and other in the Consolidated Statements of Financial Position as at December 31, 2020.

On October 15, 2021, Westcoast redeemed its Cumulative Five-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 12 with a par value of $300 million. As a result, we recorded a decrease of $293 million, which represents the par value less related issuance costs, in Noncontrolling interests for the year ended December 31, 2021.

21.  SHARE CAPITAL
Our authorized share capital consists of an unlimited number of common shares with no par value and an unlimited number of preference shares.

COMMON SHARES
202120202019
NumberNumberNumber
December 31,of SharesAmountof SharesAmountof SharesAmount
(millions of Canadian dollars; number of shares in millions)
Balance at beginning of year2,026 64,768 2,025 64,746 2,022 64,677 
Shares issued on exercise of stock options 31 22 69 
Balance at end of year2,026 64,799 2,026 64,768 2,025 64,746 

142


PREFERENCE SHARES
202120202019
NumberNumberNumber
December 31,of SharesAmountof SharesAmountof SharesAmount
(millions of Canadian dollars; number of shares in millions)
Preference Shares, Series A5 125 125 125 
Preference Shares, Series B18 457 18 457 18 457 
Preference Shares, Series C2 43 43 43 
Preference Shares, Series D18 450 18 450 18 450 
Preference Shares, Series F20 500 20 500 20 500 
Preference Shares, Series H14 350 14 350 14 350 
Preference Shares, Series J8 199 199 199 
Preference Shares, Series L16 411 16 411 16 411 
Preference Shares, Series N18 450 18 450 18 450 
Preference Shares, Series P16 400 16 400 16 400 
Preference Shares, Series R16 400 16 400 16 400 
Preference Shares, Series 116 411 16 411 16 411 
Preference Shares, Series 324 600 24 600 24 600 
Preference Shares, Series 58 206 206 206 
Preference Shares, Series 710 250 10 250 10 250 
Preference Shares, Series 911 275 11 275 11 275 
Preference Shares, Series 1120 500 20 500 20 500 
Preference Shares, Series 1314 350 14 350 14 350 
Preference Shares, Series 1511 275 11 275 11 275 
Preference Shares, Series 1730 750 30 750 30 750 
Preference Shares, Series 1920 500 20 500 20 500 
Issuance costs(155)(155)(155)
Balance at end of year 7,747 7,747 7,747 

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Characteristics of the preference shares are as follows:
Dividend Rate
Dividend1
Per Share Base
Redemption
Value2
Redemption and
Conversion
Option Date2,3
Right to
Convert
Into3,4
(Canadian dollars unless otherwise stated)
Preference Shares, Series A5.50 %$1.37500$25— — 
Preference Shares, Series B3.42 %$0.85360$25June 1, 2022Series C
Preference Shares, Series C5
3-month treasury bill plus 2.40%— $25June 1, 2022Series B
Preference Shares, Series D4.46 %$1.11500$25March 1, 2023Series E
Preference Shares, Series F4.69 %$1.17224$25June 1, 2023Series G
Preference Shares, Series H4.38 %$1.09400$25September 1, 2023Series I
Preference Shares, Series J4.89 %US$1.22160US$25June 1, 2022Series K
Preference Shares, Series L4.96 %US$1.23972US$25September 1, 2022Series M
Preference Shares, Series N5.09 %$1.27152$25December 1, 2023Series O
Preference Shares, Series P4.38 %$1.09476$25March 1, 2024Series Q
Preference Shares, Series R4.07 %$1.01825$25June 1, 2024Series S
Preference Shares, Series 15.95 %US$1.48728US$25June 1, 2023Series 2
Preference Shares, Series 33.74 %$0.93425$25September 1, 2024Series 4
Preference Shares, Series 55.38 %US$1.34383US$25March 1, 2024Series 6
Preference Shares, Series 74.45 %$1.11224$25March 1, 2024Series 8
Preference Shares, Series 94.10 %$1.02424$25December 1, 2024Series 10
Preference Shares, Series 113.94 %$0.98452$25March 1, 2025Series 12
Preference Shares, Series 133.04 %$0.76076$25June 1, 2025Series 14
Preference Shares, Series 152.98 %$0.74576$25September 1, 2025Series 16
Preference Shares, Series 175.15 %$1.28750$25March 1, 2022Series 18
Preference Shares, Series 194.90 %$1.22500$25March 1, 2023Series 20
1The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this feature.
2Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.
3The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a 1-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value.
4With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in a year) x three-month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in a year) x three-month US Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6).
5The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.15501 from $0.15349 on March 1, 2021, was increased to $0.15753 from $0.15501 on June 1, 2021, was increased to $0.16081 from $0.15753 on September 1, 2021 and was decreased to $0.15719 from $0.16081 on December 1, 2021, due to reset on a quarterly basis following the issuance thereof.

PREFERENCE SHARE REDEMPTION
We intend to exercise our right to redeem all of our outstanding cumulative redeemable minimum rate reset preference shares, Series 17, on March 1, 2022 at a price of $25 per Series 17 share, together with all accrued and unpaid dividends, if any.

144


SHAREHOLDER RIGHTS PLAN
The Shareholder Rights Plan is designed to encourage the fair treatment of our shareholders in connection with any takeover offer. Rights issued under the plan become exercisable when a person and any related parties acquires or announces its intention to acquire 20% or more of our outstanding common shares without complying with certain provisions set out in the plan or without approval of our Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase our common shares at a 50% discount to the market price at that time.

22.  STOCK OPTION AND STOCK UNIT PLANS

We maintain 3 long-term incentive compensation plans: the ISO Plan, the PSU Plan and the RSU Plan. Total stock-based compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 was $157 million, $145 million and $117 million, respectively. Disclosure of activity and assumptions for material stock-based compensation plans are included below.
INCENTIVE STOCK OPTIONS
Certain key employees are granted ISOs to purchase common shares at the grant date market price. ISOs vest in equal annual installments over a four-year period and expire 10 years after the issue date.
December 31, 2021Number
Weighted
Average
Exercise
Price
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
(options in thousands; intrinsic value in millions of Canadian dollars; weighted average exercise price in Canadian dollars)    
Options outstanding at beginning of year35,494 48.65   
Options granted4,072 43.86   
Options exercised1
(4,142)41.85   
Options cancelled or expired(1,407)50.74   
Options outstanding at end of year34,017 49.28 5.7128 
Options vested at end of year2
22,029 49.84 4.564 
1The total intrinsic value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $24 million, $13 million and $58 million, respectively, and cash received on exercise was $2 million, $4 million and $1 million, respectively.
2The total fair value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $25 million, $30 million and $32 million, respectively.

145


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 31,202120202019
Fair value per option (Canadian dollars)1
4.10 4.01 4.37 
Valuation assumptions
Expected option term (years)2
665
Expected volatility3
25.5 %18.3 %19.9 %
Expected dividend yield4
7.6 %5.9 %6.1 %
Risk-free interest rate5
0.7 %1.3 %2.0 %
1Options granted to US employees are based on NYSE prices. The option value and assumptions shown are based on a weighted average of the US and the Canadian options. The fair values per option for the years ended December 31, 2021, 2020 and 2019 were $3.91, $3.75 and $4.04, respectively, for Canadian employees and US$3.65, US$3.62 and US$4.09, respectively, for US employees.
2The expected option term is six years based on historical exercise practice and five years for retirement eligible employees.
3Expected 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.
4The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.
5The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the US Treasury Bond Yields.

Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for ISOs was $16 million, $24 million and $32 million, respectively. As at December 31, 2021, unrecognized compensation expense related to non-vested stock-based compensation arrangements granted under the ISO Plan was $11 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.
PERFORMANCE STOCK UNITS
Under PSU awards for certain key employees, cash awards are paid following a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by Enbridge's weighted average share price for 20 days prior to the maturity of the grant and by a performance multiplier. The performance multiplier ranges from zero, if our performance fails to meet threshold performance levels, to a maximum of 2 if we perform within the highest range of the performance targets. The performance multiplier is derived through a calculation of our Total Shareholder Return percentile rank, in each case relative to a specified peer group of companies and our distributable cash flow per share, adjusted for unusual, non-operating or non-recurring items, relative to targets established at the time of grant. To calculate the 2021 expense, a multiplier of 0.5 was used for 2021 PSU grants, 0.5 for 2020 PSU grants and 1.3 for the 2019 PSU grants.
December 31, 2021Number
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
(units in thousands; intrinsic value in millions of Canadian dollars)   
Units outstanding at beginning of year3,056 
Units granted1,895 
Units cancelled(76)
Units matured1
(1,664)
Dividend reinvestment218 
Units outstanding at end of year3,429 1.1181 
1The total amount paid during the years ended December 31, 2021, 2020 and 2019 for PSUs was $70 million, $14 million and $19 million, respectively.
146


Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for PSUs was $56 million, $76 million and $40 million, respectively. As at December 31, 2021, unrecognized compensation expense related to non-vested PSUs was $31 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.

RESTRICTED STOCK UNITS
Under RSU awards, cash awards are paid to certain of our employees vesting in equal installments on each of the first, second and third anniversaries of the grant date. Share settled awards are given to certain senior management employees following a three year maturity period. RSU holders receive cash or shares equal to our weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date.
December 31, 2021Number
Weighted
Average
Remaining
Contractual Life (years)
Aggregate
Intrinsic Value
(units in thousands; intrinsic value in millions of Canadian dollars)
Units outstanding at beginning of year2,453   
Units granted1,514   
Units cancelled(75)  
Units matured1
(1,433)  
Dividend reinvestment246   
Units outstanding at end of year2,705 1.1129 
1The total amount paid during the years ended December 31, 2021, 2020 and 2019 for RSUs was $72 million, $27 million and $34 million, respectively.
Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for RSUs was $85 million, $44 million and $41 million, respectively. As at December 31, 2021, unrecognized compensation expense related to non-vested RSUs was $62 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.

147


23.  COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
Changes in AOCI attributable to our common shareholders for the years ended December 31, 2021, 2020 and 2019 are as follows:
Cash Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
Total
(millions of Canadian dollars)      
Balance at January 1, 2021(1,326)5 (215)568 66 (499)(1,401)
Other comprehensive income/(loss) retained in AOCI238 (5)49 (492)(12)520 298 
Other comprehensive (income)/loss reclassified to earnings      
Interest rate contracts1
296      296 
Commodity contracts2
1      1 
Foreign exchange contracts3
5      5 
Other contracts4
2      2 
Equity investment disposal    (66) (66)
 Amortization of pension and OPEB actuarial loss and prior service costs5
     28 28 
Other17   (20)3   
 559 (5)49 (512)(75)548 564 
Tax impact      
Income tax on amounts retained in AOCI(61)    (126)(187)
Income tax on amounts reclassified to earnings(69)   4 (7)(72)
 (130)   4 (133)(259)
Balance at December 31, 2021(897) (166)56 (5)(84)(1,096)
Cash Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
Total
(millions of Canadian dollars)
Balance at January 1, 2020(1,073)— (317)1,396 67 (345)(272)
Other comprehensive income/(loss) retained in AOCI(591)115 (828)(2)(221)(1,522)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1
253 — — — — — 253 
Foreign exchange contracts3
— — — — — 
Other contracts4
(2)— — — — — (2)
 Amortization of pension and OPEB actuarial loss and prior service costs5
— — — — — 17 17 
(335)115 (828)(2)(204)(1,249)
Tax impact
Income tax on amounts retained in AOCI140 — (13)— 54 182 
Income tax on amounts reclassified to earnings(58)— — — — (4)(62)
82 — (13)— 50 120 
Balance at December 31, 2020(1,326)(215)568 66 (499)(1,401)
148


Cash Flow
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
Total
(millions of Canadian dollars)
Balance at January 1, 2019(770)(598)4,323 34 (317)2,672 
Other comprehensive income/(loss) retained in AOCI(599)320 (2,927)34 (124)(3,296)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1
157 — — — — 157 
Commodity contracts2
(1)— — — — (1)
Foreign exchange contracts3
— — — — 
Other contracts4
(3)— — — — (3)
 Amortization of pension and OPEB actuarial loss and prior service costs5
— — — — 17 17 
(441)320 (2,927)34 (107)(3,121)
Tax impact
Income tax on amounts retained in AOCI169 (39)— 28 164 
Income tax on amounts reclassified to earnings(31)— — — (4)(35)
138 (39)— 24 129 
Other— — — (7)55 48 
Balance at December 31, 2019(1,073)(317)1,396 67 (345)(272)
1Reported within Interest expense in the Consolidated Statements of Earnings.
2Reported within Transportation and other services revenue, Commodity sales revenue, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
3Reported within Transportation and other services revenue and Net foreign currency gain in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
5These components are included in the computation of net benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

24.  RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
MARKET RISK
Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risks). Formal risk management policies, processes and systems have been designed to mitigate these risks.
The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.
Foreign Exchange Risk
We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in US dollar denominated investments and subsidiaries using foreign currency derivatives and US dollar denominated debt.
149


Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a program to mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 3.9%.

We are exposed to changes in the fair value of fixed rate debt that arise as a result of changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in fair value via execution of fixed to floating interest rate swaps. As at December 31, 2021, we do not have any pay floating-receive fixed interest rate swaps outstanding.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 2.0%.
Commodity Price Risk
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS
The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments.
We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances.

150


The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.

December 31, 2021
Derivative
Instruments
Used as
Cash Flow Hedges
Derivative
Instruments
Used as Net
Investment Hedges
Derivative
Instruments
Used as
Fair Value Hedges
Non-
Qualifying
Derivative Instruments
Total Gross
Derivative
Instruments as Presented
Amounts
Available for Offset
Total Net
Derivative Instruments
(millions of Canadian dollars)      
Accounts receivable and other      
Foreign exchange contracts   259 259 (41)218 
Interest rate contracts64    64  64 
Commodity contracts   204 204 (129)75 
Other contracts   2 2  2 
 64   465 529 (170)359 
Deferred amounts and other assets    
Foreign exchange contracts   240 240 (61)179 
Interest rate contracts88    88 (1)87 
Commodity contracts   29 29 (13)16 
Other contracts   3 3  3 
 88   272 360 (75)285 
Accounts payable and other    
Foreign exchange contracts(15) (112)(176)(303)41 (262)
Interest rate contracts(150)   (150) (150)
Commodity contracts(14)  (250)(264)129 (135)
Other contracts       
(179) (112)(426)(717)170 (547)
Other long-term liabilities    
Foreign exchange contracts   (423)(423)61 (362)
Interest rate contracts(1)  (23)(24)1 (23)
Commodity contracts(17)  (67)(84)13 (71)
Other contracts       
(18)  (513)(531)75 (456)
Total net derivative asset/(liability)    
Foreign exchange contracts(15) (112)(100)(227) (227)
Interest rate contracts1   (23)(22) (22)
Commodity contracts(31)  (84)(115) (115)
Other contracts   5 5  5 
 (45) (112)(202)(359) (359)
151


December 31, 2020Derivative
Instruments
Used as
Cash Flow Hedges
Derivative
Instruments
Used as Net Investment Hedges
Derivative
Instruments
Used as Fair Value Hedges
Non-
Qualifying
Derivative Instruments
Total Gross
Derivative
Instruments as Presented
Amounts
Available for Offset
Total Net
Derivative Instruments
(millions of Canadian dollars)      
Accounts receivable and other      
Foreign exchange contracts— — — 180 180 (28)152 
Interest rate contracts— — — — — — — 
Commodity contracts— — — 143 143 (81)62 
Other contracts— — — — — — — 
 — — — 323 323 (109)214 
Deferred amounts and other assets    
   Foreign exchange contracts14 — — 452 466 (218)248 
   Interest rate contracts56 — — — 56 (25)31 
   Commodity contracts— — — 39 39 (9)30 
   Other contracts— — — — — — — 
 70 — — 491 561 (252)309 
Accounts payable and other    
   Foreign exchange contracts(5)— (29)(151)(185)28 (157)
   Interest rate contracts(423)— — (2)(425)— (425)
   Commodity contracts(2)— — (278)(280)81 (199)
   Other contracts(1)— — (3)(4)— (4)
 (431)— (29)(434)(894)109 (785)
Other long-term liabilities    
   Foreign exchange contracts— — (87)(673)(760)218 (542)
   Interest rate contracts(218)— — (23)(241)25 (216)
   Commodity contracts(1)— — (57)(58)(49)
Other contracts— — — — — — — 
 (219)— (87)(753)(1,059)252 (807)
Total net derivative asset/(liability)    
   Foreign exchange contracts— (116)(192)(299)— (299)
   Interest rate contracts(585)— — (25)(610)— (610)
   Commodity contracts(3)— — (153)(156)— (156)
   Other contracts(1)— — (3)(4)— (4)
 (580)— (116)(373)(1,069)— (1,069)
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The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.
20212020
As at December 31,20222023202420252026ThereafterTotalTotal
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)
2,508      2,508 3,522 
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)
9,245 5,596 4,346 3,174 2,574 492 25,427 17,859 
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)
28 29 30 30 28 32 177 265 
Foreign exchange contracts - Euro forwards - sell (millions of Euro)
104 92 91 86 85 343 801 885 
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)
72,500      72,500 72,500 
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)
395 47 35 30 26 64 597 4,635 
Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars)
2,363 1,784 1,132    5,279 5,396 
Equity contracts (millions of Canadian dollars)
20 26 21    67 62 
Commodity contracts - natural gas (billions of cubic feet)
165 18 5 11   199 173 
Commodity contracts - crude oil (millions of barrels)
12      12 15 
Commodity contracts - power (megawatt per hour (MW/H)
(43)(43)(43)(43)  (43)1(35)1
1Total is an average net purchase/(sell) of power.

153


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:
 202120202019
(millions of Canadian dollars)   
Amount of unrealized gain/(loss) recognized in OCI   
Cash flow hedges   
Foreign exchange contracts(29)(1)(19)
Interest rate contracts252 (595)(559)
Commodity contracts(28)(25)
Other contracts1 (3)10 
Fair value hedges
Foreign exchange contracts(5)— 
Net investment hedges   
Foreign exchange contracts 13 
 191 (579)(591)
Amount of (gain)/loss reclassified from AOCI to earnings   
Foreign exchange contracts1
5 
Interest rate contracts2
296 253 157 
Commodity contracts3
1 — (1)
Other contracts4
2 (2)(3)
 304 256 158 
1Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
2Reported within Interest expense in the Consolidated Statements of Earnings.
3Reported within Transportation and other services revenue, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expenses in the Consolidated Statements of Earnings.
We estimate that a loss of $47 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 36 months as at December 31, 2021.

Fair Value Derivatives
For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings.

Year ended December 31,20212020
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative8 (116)
Unrealized gain/(loss) on hedged item(15)133 
Realized loss on derivative(41)(12)
Realized gain on hedged item45 — 

154


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 31,202120202019
(millions of Canadian dollars)   
Foreign exchange contracts1
92 902 1,626 
Interest rate contracts2
2 (25)178 
Commodity contracts3
71 (114)(62)
Other contracts4
8 (7)
Total unrealized derivative fair value gain/(loss), net173 756 1,751 
1For the respective annual periods, reported within Transportation and other services revenue (2021 - $98 million gain; 2020 - $533 million gain; 2019 - $930 million gain) and Net foreign currency gain/(loss) (2021 - $6 million loss; 2020 - $369 million gain; 2019 - $696 million gain) in the Consolidated Statements of Earnings.
2Reported as an increase within Interest expense in the Consolidated Statements of Earnings.
3For the respective annual periods, reported within Transportation and other services revenue (2021 - $9 million gain; 2020 - $2 million loss; 2019 - $26 million loss), Commodity sales (2021 - $160 million gain; 2020 - $321 million loss; 2019 - $544 million loss), Commodity costs (2021 - $105 million loss; 2020 - $207 million gain; 2019 - $459 million gain) and Operating and administrative expense (2021 - $7 million gain; 2020 - $2 million gain; 2019 - $49 million gain) in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. We also maintain current shelf prospectuses with securities regulators which enables ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2021. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.

CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.

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We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:
December 31,20212020
(millions of Canadian dollars)  
Canadian financial institutions424 481 
US financial institutions130 99 
European financial institutions181 28 
Asian financial institutions30 167 
Other1
122 97 
 887 872 
1Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at December 31, 2021, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association agreements. We held no cash collateral on derivative asset exposures as at December 31, 2021 and December 31, 2020.
Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates, and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation.
Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Enbridge Gas, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we classify and provide for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.
FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.
FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.
Level 1
Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange traded derivatives used to mitigate the risk of crude oil price fluctuations.
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Level 2
Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps for which observable inputs can be obtained.

We have also categorized the fair value of our held to maturity preferred share investment and long-term debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor.
Level 3
Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power contracts and NGL and natural gas contracts, basis swaps, commodity swaps, power and energy swaps, as well as physical forward commodity contracts. We do not have any other financial instruments categorized in Level 3.

We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value.

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We have categorized our derivative assets and liabilities measured at fair value as follows:
December 31, 2021Level 1Level 2Level 3Total Gross Derivative Instruments
(millions of Canadian dollars)    
Financial assets    
Current derivative assets    
Foreign exchange contracts 259  259 
Interest rate contracts 64  64 
Commodity contracts38 71 95 204 
Other contracts 2  2 
 38 396 95 529 
Long-term derivative assets   
Foreign exchange contracts 240  240 
Interest rate contracts 88  88 
Commodity contracts 21 8 29 
Other contracts 3  3 
  352 8 360 
Financial liabilities   
Current derivative liabilities   
Foreign exchange contracts (303) (303)
Interest rate contracts (150) (150)
Commodity contracts(52)(66)(146)(264)
Other contracts    
 (52)(519)(146)(717)
Long-term derivative liabilities   
Foreign exchange contracts (423) (423)
Interest rate contracts (24) (24)
Commodity contracts (19)(65)(84)
Other contracts    
  (466)(65)(531)
Total net financial asset/(liability)   
Foreign exchange contracts (227) (227)
Interest rate contracts (22) (22)
Commodity contracts(14)7 (108)(115)
Other contracts 5  5 
 (14)(237)(108)(359)
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December 31, 2020Level 1Level 2Level 3Total Gross Derivative Instruments
(millions of Canadian dollars)    
Financial assets    
Current derivative assets    
Foreign exchange contracts— 180 — 180 
Interest rate contracts— — — — 
Commodity contracts43 33 67 143 
Other contracts— — — — 
 43 213 67 323 
Long-term derivative assets   
Foreign exchange contracts— 466 — 466 
Interest rate contracts— 56 — 56 
Commodity contracts24 14 39 
Other contracts— — — — 
 546 14 561 
Financial liabilities   
Current derivative liabilities   
Foreign exchange contracts— (185)— (185)
Interest rate contracts— (425)— (425)
Commodity contracts(39)(18)(223)(280)
Other contracts— (4)— (4)
 (39)(632)(223)(894)
Long-term derivative liabilities   
Foreign exchange contracts— (760)— (760)
Interest rate contracts— (241)— (241)
Commodity contracts(1)(8)(49)(58)
Other contracts— — — — 
 (1)(1,009)(49)(1,059)
Total net financial asset/(liability)   
Foreign exchange contracts— (299)— (299)
Interest rate contracts— (610)— (610)
Commodity contracts31 (191)(156)
Other contracts— (4)— (4)
 (882)(191)(1,069)
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
December 31, 2021Fair ValueUnobservable InputMinimum PriceMaximum PriceWeighted Average PriceUnit of Measurement
(fair value in millions of Canadian dollars)      
Commodity contracts - financial1
      
Natural gas(19)Forward gas price3.129.054.49
$/mmbtu2
Crude3 Forward crude price76.0298.9991.73$/barrel
Power(60)Forward power price31.00125.1376.23$/MW/H
Commodity contracts - physical1
      
Natural gas(56)Forward gas price2.659.254.63
$/mmbtu2
Crude24 Forward crude price68.6697.0087.97$/barrel
 (108)     
1Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2One million British thermal units (mmbtu).
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If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices, and for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility.

Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:
Year ended December 31,20212020
(millions of Canadian dollars)  
Level 3 net derivative liability at beginning of period(191)(69)
Total gain/(loss)  
Included in earnings1
(39)(123)
Included in OCI(29)
Settlements151 (1)
Level 3 net derivative liability at end of period(108)(191)
1Reported within Transportation and other services revenue, Commodity costs and Operating and administrative expenses in the Consolidated Statements of Earnings.
There were no transfers into or out of Level 3 as at December 31, 2021 or 2020.

NET INVESTMENT HEDGES
We have designated a portion of our US dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of our net investment in US dollar denominated investments and subsidiaries.
During the years ended December 31, 2021 and 2020, we recognized unrealized foreign exchange gains of $49 million and $117 million, respectively, on the translation of US dollar denominated debt and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of NaN and $13 million, respectively, in OCI. During the years ended December 31, 2021 and 2020, we recognized a realized loss of NaN and $15 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts. NaN realized gains or losses associated with the settlement of US dollar denominated debt that had matured during the period were recognized in OCI during the years ended December 31, 2021 and 2020.

FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS
Certain long-term investments in other entities with no actively quoted prices are classified as FVMA investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $52 million as at December 31, 2021 and 2020.

We have Restricted long-term investments held in trust totaling $630 million and $553 million as at December 31, 2021 and 2020, respectively, which are recognized at fair value.
As at December 31, 2021 and 2020, our long-term debt had a carrying value of $74.4 billion and $66.1 billion, respectively, before debt issuance costs and a fair value of $82.0 billion and $75.1 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at December 31, 2021 and 2020, the non-current notes receivable had a carrying value of $1.0 billion and $1.1 billion, respectively, which also approximates their fair value.

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The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, restricted long-term investments and long-term debt approximate their cost due to the short period to maturity.

25. INCOME TAXES

INCOME TAX RATE RECONCILIATION
Year ended December 31,202120202019
(millions of Canadian dollars)   
Earnings before income taxes7,7294,190 7,535 
Canadian federal statutory income tax rate15 %15 %15 %
Expected federal taxes at statutory rate1,159629 1,130 
Increase/(decrease) resulting from:   
Provincial and state income taxes1
228 288 415 
Foreign and other statutory rate differentials2
134 (53)129 
Effects of rate-regulated accounting3
(139)(145)(63)
Foreign allowable interest deductions4
 (4)(29)
Part VI.1 tax, net of federal Part I deduction5
73 76 78 
US Minimum Tax6
 44 67 
Non-taxable portion of gain on sale of investment7
(23)— — 
Valuation allowance8
5 (6)26 
Intercorporate investments9
 — (14)
Noncontrolling interests(17)(8)(13)
Other(5)(47)(18)
Income tax expense1,415 774 1,708 
Effective income tax rate18.3%18.5%22.7%
1 The change in provincial and state income taxes from 2020 to 2021 reflects the 2020 impact of state tax apportionment and rate changes in both the US and Canada offset by the increase in earnings from US and Canadian operations in 2021.
2 The change in foreign and other statutory rate differentials from 2020 to 2021 reflects the increase in earnings from US operations partially offset by higher rate benefits from foreign operations.
3 The amount in 2019 included the federal component of the tax benefit of the write-off of regulatory assets.
4 The decrease in foreign allowable interest deductions from 2019 to 2021 was due to changes in the related loan portfolio.
5 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada.
6 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation.
7 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco.
8 The increase in 2021 is due to the federal component of the tax effect of a valuation allowance on additional deferred tax assets that are not more likely than not to be realized.
9 The amount in 2019 relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate investments such that deferred tax related to outside basis temporary differences was required to be recorded for MATL.
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COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES
Year ended December 31,202120202019
(millions of Canadian dollars)   
Earnings before income taxes   
Canada3,399 2,789 3,560 
US3,336 407 3,115 
Other994 994 860 
 7,729 4,190 7,535 
Current income taxes   
Canada162 165 347 
US80 64 107 
Other82 98 98 
 324 327 552 
Deferred income taxes   
Canada344 378 490 
US741 66 672 
Other6 (6)
 1,091 447 1,156 
Income tax expense1,415 774 1,708 

COMPONENTS OF DEFERRED INCOME TAXES
Deferred income tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are as follows:

December 31,20212020
(millions of Canadian dollars)  
Deferred income tax liabilities  
Property, plant and equipment(8,721)(7,786)
Investments(6,097)(4,649)
Regulatory assets(1,245)(1,156)
Other(208)(127)
Total deferred income tax liabilities(16,271)(13,718)
Deferred income tax assets  
Financial instruments315 518 
Pension and OPEB plans110 251 
Loss carryforwards3,081 2,005 
Other1,648 1,461 
Total deferred income tax assets5,154 4,235 
Less valuation allowance(84)(79)
Total deferred income tax assets, net5,070 4,156 
Net deferred income tax liabilities(11,201)(9,562)
Presented as follows:
Total deferred income tax assets488 770 
Total deferred income tax liabilities(11,689)(10,332)
Net deferred income tax liabilities(11,201)(9,562)

A valuation allowance has been established for certain loss and credit carryforwards, and outside basis temporary differences on investments that reduce deferred income tax assets to an amount that will more likely than not be realized.
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As at December 31, 2021, we recognized the benefit of unused tax loss carryforwards of $1.9 billion (2020 - $2.6 billion) in Canada which expire in 2026 and beyond.

As at December 31, 2021, we recognized the benefit of unused tax loss carryforwards of $11.0 billion (2020 - $5.8 billion) in the US. Unused tax loss carryforwards of $3.5 billion (2020 - $2.4 billion) begin to expire in 2023, and unused tax loss carryforwards of $7.5 billion (2020 - $3.4 billion) have no expiration.

We have not provided for deferred income taxes on the difference between the carrying value of substantially all of our foreign subsidiaries and their corresponding tax basis as the earnings of those subsidiaries are intended to be permanently reinvested in their operations. As such, these investments are not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying values of the investments and their tax bases is largely a result of unremitted earnings and currency translation adjustments. The unremitted earnings and currency translation adjustment for which no deferred taxes have been recognized in respect of foreign subsidiaries were $4.3 billion and $5.5 billion for the periods December 31, 2021 and 2020, respectively. If such earnings are remitted, in the form of dividends or otherwise, we may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is not practicable.

Enbridge and certain of our subsidiaries are subject to taxation in Canada, the US and other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations include the US (Federal) and Canada (Federal, Alberta and Ontario). We are open to examination by Canadian tax authorities for the 2012 to 2021 tax years and by US tax authorities for the 2018 to 2021 tax years. We are currently under examination for income tax matters in Canada for the 2014 to 2018 tax years. We are not currently under examination for income tax matters in any other material jurisdiction where we are subject to income tax.

UNRECOGNIZED TAX BENEFITS
Year ended December 31,20212020
(millions of Canadian dollars)
Unrecognized tax benefits at beginning of year121 129 
Gross increases for tax positions of current year1 
Gross decreases for tax positions of prior year(26)(1)
Change in translation of foreign currency(1)(3)
Lapses of statute of limitations(19)(5)
Unrecognized tax benefits at end of year76 121 
The unrecognized tax benefits as at December 31, 2021, if recognized, would impact our effective income tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on our consolidated financial statements.

We recognize accrued interest and penalties related to unrecognized tax benefits as a component of income taxes. Interest and penalties included in income taxes for the years ended December 31, 2021 and 2020 were a $5 million recovery and $3 million expense, respectively. As at December 31, 2021 and 2020, interest and penalties of $12 million and $17 million, respectively, have been accrued.

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26.  PENSION AND OTHER POSTRETIREMENT BENEFITS
PENSION PLANS
We sponsor Canadian and US contributory and non-contributory registered defined benefit and defined contribution pension plans, which provide benefits covering substantially all employees. The Canadian Plans provide defined benefit and defined contribution pension benefits to our Canadian employees. The US Plans provide defined benefit pension benefits to our US employees. We also sponsor supplemental non-contributory defined benefit pension plans, which provide non-registered benefits for certain employees in Canada and the US.

Defined Benefit Pension Plan Benefits
Benefits payable from the defined benefit pension plans are based on each plan participant’s years of service and final average remuneration. Some benefits are partially inflation-indexed after a plan participant’s retirement. Our contributions are made in accordance with independent actuarial valuations. Participant contributions to contributory defined benefit pension plans are based upon each plan participant’s current eligible remuneration.

Defined Contribution Pension Plan Benefits
Our contributions are based on each plan participant’s current eligible remuneration. Our contributions for some defined contribution pension plans are also based on age and years of service. Our defined contribution pension benefit costs are equal to the amount of contributions required to be made by us.
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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:
 CanadaUS
December 31,2021202020212020
(millions of Canadian dollars)    
Change in projected benefit obligation    
Projected benefit obligation at beginning of year4,855 4,446 1,243 1,230 
Service cost139 148 44 44 
Interest cost101 128 17 31 
Participant contributions28 31  — 
Actuarial (gain)/loss1
(329)292 (21)95 
Benefits paid(194)(190)(84)(128)
Foreign currency exchange rate changes — (11)(23)
Other — (4)(6)
Projected benefit obligation at end of year2
4,600 4,855 1,184 1,243 
Change in plan assets
Fair value of plan assets at beginning of year4,077 3,827 1,062 1,104 
Actual return on plan assets505 288 151 83 
Employer contributions120 121 43 27 
Participant contributions28 31  — 
Benefits paid(194)(190)(84)(128)
Foreign currency exchange rate changes — (8)(18)
Other — (4)(6)
Fair value of plan assets at end of year3
4,536 4,077 1,160 1,062 
Underfunded status at end of year(64)(778)(24)(181)
Presented as follows:
Deferred amounts and other assets250 35 98 — 
Accounts payable and other(9)(9)(4)(3)
Other long-term liabilities(305)(804)(118)(178)
 (64)(778)(24)(181)
1Primarily due to increase in the discount rate used to measure the benefit obligations (2020 - primarily due to decrease in the discount rate used to measure the benefit obligations).
2The accumulated benefit obligation for our Canadian pension plans was $4.3 billion and $4.5 billion as at December 31, 2021 and 2020, respectively. The accumulated benefit obligation for our US pension plans was $1.1 billion and $1.2 billion as at December 31, 2021 and 2020, respectively.
3Assets in the amount of $13 million (2020 - $11 million) and $84 million (2020 - $59 million), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in grantor trusts and rabbi trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes.

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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:
 CanadaUS
December 31,2021202020212020
(millions of Canadian dollars)
Accumulated benefit obligation440 4,094 115 1,207 
Fair value of plan assets247 3,621  1,062 

Certain of our pension plans have projected benefit obligations in excess of the fair value of plan assets. For these plans, the projected benefit obligation and fair value of plan assets were as follows:
 CanadaUS
December 31,2021202020212020
(millions of Canadian dollars)
Projected benefit obligation1,272 4,434 121 1,243 
Fair value of plan assets1,020 3,621  1,062 

Amount Recognized in Accumulated Other Comprehensive Income
The amount of pre-tax AOCI relating to our pension plans are as follows:
 CanadaUS
December 31,2021202020212020
(millions of Canadian dollars)    
Net actuarial loss226 542 92 233 
Prior service credit — (1)(1)
Total amount recognized in AOCI1
226 542 91 232 
1 Excludes amounts related to cumulative translation adjustment.

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:
CanadaUS
Year ended December 31,202120202019202120202019
(millions of Canadian dollars)
Service cost139 148 149 44 44 45 
Interest cost1
101 128 139 17 31 41 
Expected return on plan assets1
(252)(260)(245)(73)(88)(78)
Amortization/settlement of net actuarial loss1
54 42 41 11 
Amortization/curtailment of prior service credit1
 — —  (1)(1)
Net periodic benefit (credit)/cost42 58 84 (1)(13)
Defined contribution benefit cost7  — — 
Net pension (credit)/cost recognized in Earnings49 64 92 (1)(13)
Amount recognized in OCI:
Effect of plan combination — —  — (6)
 Amortization/settlement of net actuarial loss(25)(21)(26)(11)(1)(2)
Amortization/curtailment of prior service credit — —  
Net actuarial (gain)/loss arising during the year(291)118 115 (99)100 
Total amount recognized in OCI(316)97 89 (110)100 
Total amount recognized in Comprehensive income(267)161 181 (111)87 10 
1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.

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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:
 CanadaUS
202120202019202120202019
Projected benefit obligation
Discount rate3.2 %2.6 %3.0 %2.6 %2.2 %3.0 %
Rate of salary increase2.9 %2.3 %3.2 %2.8 %2.7 %2.9 %
Cash balance interest credit rateN/AN/AN/A4.3 %4.3 %4.5 %
Net periodic benefit cost
Discount rate2.6 %3.0 %3.8 %2.2 %3.0 %3.9 %
Rate of return on plan assets6.2 %6.8 %7.0 %7.3 %7.9 %8.0 %
Rate of salary increase2.3 %3.2 %3.2 %2.7 %2.9 %2.9 %
Cash balance interest credit rateN/AN/AN/A4.3 %4.5 %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.

167


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:
 CanadaUS
December 31,2021202020212020
(millions of Canadian dollars)    
Change in accumulated postretirement benefit obligation    
Accumulated postretirement benefit obligation at beginning of year321 293 254 288 
Service cost6 1 
Interest cost7 3 
Participant contributions — 8 
Actuarial (gain)/loss1
(51)21 (69)17 
Benefits paid(9)(6)(22)(28)
Plan amendments —  (33)
Foreign currency exchange rate changes — (3)(4)
Other — 1 
Accumulated postretirement benefit obligation at end of year274 321 173 254 
Change in plan assets
Fair value of plan assets at beginning of year — 188 188 
Actual return on plan assets — 22 14 
Employer contributions9 6 12 
Participant contributions — 8 
Benefits paid(9)(6)(22)(28)
Foreign currency exchange rate changes — (3)(3)
Other — 2 
Fair value of plan assets at end of year — 201 188 
Overfunded/(underfunded) status at end of year(274)(321)28 (66)
Presented as follows:
Deferred amounts and other assets — 71 19 
Accounts payable and other(12)(13) (6)
Other long-term liabilities(262)(308)(43)(79)
 (274)(321)28 (66)
1 Primarily due to increase in the discount rate used to measure the benefit obligations (2020 - primarily due to decrease in the discount rate used to measure the benefit obligations).

168


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:
 CanadaUS
December 31,2021202020212020
(millions of Canadian dollars)
Accumulated benefit obligation274 321 94 191 
Fair value of plan assets — 51 106 

Amount Recognized in Accumulated Other Comprehensive Income
The amount of pre-tax AOCI relating to our OPEB plans are as follows:
 CanadaUS
December 31,2021202020212020
(millions of Canadian dollars)    
Net actuarial (gain)/loss(35)15 (104)(7)
Prior service credit(1)(1)(37)(44)
Total amount recognized in AOCI1
(36)14 (141)(51)
1 Excludes amounts related to cumulative translation adjustment.

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:
 CanadaUS
Year ended December 31,202120202019202120202019
(millions of Canadian dollars)      
Service cost6 1 
Interest cost1
7 10 3 10 
Expected return on plan assets1
 — — (10)(12)(12)
Amortization/settlement of net actuarial gain1
 (1)(7)(1)(1)— 
Amortization/curtailment of prior service credit1
 — (1)(7)(2)(2)
Net periodic benefit (credit)/cost recognized in Earnings13 12 (14)(6)(2)
Amount recognized in OCI:
Amortization/settlement of net actuarial gain 1 — 
Amortization/curtailment of prior service credit — 7 
Net actuarial (gain)/loss arising during the year(50)21 15 (80)15 (8)
Prior service credit — —  (33)— 
Total amount recognized in OCI(50)22 23 (72)(15)(6)
Total amount recognized in Comprehensive income(37)34 30 (86)(21)(8)
1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.

169


Actuarial Assumptions
The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligation and net periodic benefit cost of our OPEB plans are as follows:
 CanadaUS
202120202019202120202019
Accumulated postretirement benefit obligation
Discount rate3.2 %2.6 %3.1 %2.4 %2.0 %2.8 %
Net periodic benefit cost
Discount rate2.6 %3.1 %3.8 %2.0 %2.8 %4.0 %
Rate of return on plan assetsN/AN/AN/A6.0 %6.7 %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:
CanadaUS
2021202020212020
Health care cost trend rate assumed for next year4.0 %4.0 %7.0 %6.8 %
Rate to which the cost trend is assumed to decline (ultimate trend rate)4.0 %4.0 %4.5 %4.5 %
Year that the rate reaches the ultimate trend rateN/AN/A20372037

PLAN ASSETS
We manage the investment risk of our pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) our operating environment and financial situation and our ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets.

The overall expected rate of return on plan assets is based on the asset allocation targets with estimates for returns based on long-term expectations.

The asset allocation targets and major categories of plan assets are as follows:
 CanadaUS
TargetDecember 31,TargetDecember 31,
Asset CategoryAllocation20212020Allocation20212020
Equity securities43.8 %46.7 %47.2 %45.0 %52.5 %55.6 %
Fixed income securities28.9 %29.8 %29.6 %20.1 %18.4 %17.2 %
Alternatives1
27.3 %23.5 %23.2 %34.9 %29.1 %27.2 %
1Alternatives 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.

170


Pension Plans
The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level:
 CanadaUS
Level 11
Level 22
Level 33
Total
Level 11
Level 22
Level 33
Total
(millions of Canadian dollars)        
December 31, 2021
Cash and cash equivalents180   180 10   10 
Equity securities
Canada198 228  426     
US1   1     
Global 1,693  1,693  609  609 
Fixed income securities
Government258 459  717  86  86 
Corporate 453  453  118  118 
Alternatives4
  1,064 1,064   337 337 
Forward currency contracts 2  2     
Total pension plan assets at fair value637 2,835 1,064 4,536 10 813 337 1,160 
December 31, 2020
Cash and cash equivalents213 — — 213 — — 
Equity securities
Canada178 188 — 366 — — — — 
US— — — — — — 
Global— 1,556 — 1,556 — 590 — 590 
Fixed income securities
Government207 378 — 585 — 75 — 75 
Corporate— 410 — 410 — 103 — 103 
Alternatives4
— — 912 912 — — 289 289 
Forward currency contracts— 33 — 33 — — — — 
Total pension plan assets at fair value600 2,565 912 4,077 768 289 1,062 
1Level 1 assets include assets with quoted prices in active markets for identical assets.
2Level 2 assets include assets with significant observable inputs.
3Level 3 assets include assets with significant unobservable inputs.
4Alternatives include investments in private debt, private equity, infrastructure and real estate funds.

Changes in the net fair value of pension plan assets classified as Level 3 in the fair value hierarchy were as follows:
CanadaUS
December 31,2021202020212020
(millions of Canadian dollars)   
Balance at beginning of year912 852 289 276 
Unrealized and realized gains/(losses)77 (27)38 
Purchases and settlements, net75 87 10 
Balance at end of year1,064 912 337 289 

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OPEB Plans
The following table summarizes the fair value of plan assets for our US funded OPEB plans recorded at each fair value hierarchy level:
Level 11
Level 22
Level 33
Total
(millions of Canadian dollars)    
December 31, 2021
Cash and cash equivalents4   4 
Equity securities
US 39  39 
Global 75  75 
Fixed income securities
Government47 6  53 
Corporate 8  8 
Alternatives4
  22 22 
Total OPEB plan assets at fair value51 128 22 201 
December 31, 2020
Equity securities
US— 35 — 35 
Global— 79 — 79 
Fixed income securities
Government38 — 44 
Corporate— — 
Alternatives4
— — 22 22 
Total OPEB plan assets at fair value38 128 22 188 
1Level 1 assets include assets with quoted prices in active markets for identical assets.
2Level 2 assets include assets with significant observable inputs.
3Level 3 assets include assets with significant unobservable inputs.
4Alternatives 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 31,20212020
(millions of Canadian dollars)
Balance at beginning of year22 18 
Unrealized and realized gains2 
Purchases and settlements, net(2)
Balance at end of year22 22 

EXPECTED BENEFIT PAYMENTS
Year ending December 31,202220232024202520262027-2031
(millions of Canadian dollars)      
Pension
Canada197 203 208 212 217 1,163 
US80 78 78 76 77 374 
OPEB
Canada12 12 12 13 13 67 
US17 15 14 13 12 51 
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EXPECTED EMPLOYER CONTRIBUTIONS
In 2022, we expect to contribute approximately $110 million and $4 million to the Canadian and US pension plans, respectively, and $12 million and $6 million to the Canadian and US OPEB plans, respectively.

RETIREMENT SAVINGS PLANS
In addition to the pension and OPEB plans discussed above, we also have defined contribution employee savings plans available to US employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 6.0% of eligible pay per pay period. For the years ended December 31, 2021, 2020 and 2019, pre-tax employer matching contribution costs were $27 million each year, respectively.

27. LEASES

LESSEE
We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 5 months to 25 years as at December 31, 2021.

For the years ended December 31, 2021 and 2020, we incurred operating lease expenses of $95 million and $107 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings.

For the years ended December 31, 2021 and 2020, operating lease payments to settle lease liabilities were $118 million and $133 million, respectively. Operating lease payments are reported under Operating activities in the Consolidated Statements of Cash Flows.

173


Supplemental Statements of Financial Position Information
December 31, 2021December 31,
2020
(millions of Canadian dollars, except lease term and discount rate)
Operating leases1
Operating lease right-of-use assets, net2
645708
Operating lease liabilities - current3
9280
Operating lease liabilities - long-term3
612681
Total operating lease liabilities704761
Finance leases
Finance lease right-of-use assets, net4
4957
Finance lease liabilities - current5
1311
Finance lease liabilities - long-term3
3342
Total finance lease liabilities4653
Weighted average remaining lease term
Operating leases12 years13 years
Finance leases7 years7 years
Weighted average discount rate
Operating leases4.1 %4.1 %
Finance leases3.8 %3.8 %
1Affiliate right-of-use assets, current lease liabilities and long-term lease liabilities as at December 31, 2021 were $51 million (December 31, 2020 - $65 million), $5 million (December 31, 2020 - $5 million) and $47 million (December 31, 2020 - $52 million), respectively.
2Operating lease right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position.
3Current 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.
4Finance lease right-of-use assets are reported under Property, plant and equipment, net in the Consolidated Statements of Financial Position.
5Current finance lease liabilities are reported under Current portion of long-term debt in the Consolidated Statements of Financial Position.

As at December 31, 2021, our operating and finance lease liabilities are expected to mature as follows:
Operating leasesFinance leases
(millions of Canadian dollars)
2022117 15 
202398 13 
202491 9 
202584 2 
202672 1 
Thereafter455 11 
Total undiscounted lease payments917 51 
Less imputed interest(213)(5)
Total704 46 

174


LESSOR
We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our operating leases have remaining lease terms of 1 month to 30 years as at December 31, 2021.
Year ended December 31,20212020
(millions of Canadian dollars)
Operating lease income263 265 
Variable lease income333 361 
Total lease income1
596 626 
1Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings.

As at December 31, 2021, the following table sets out future lease payments to be received under operating lease contracts where we are the lessor:
Operating leases
(millions of Canadian dollars)
2022235 
2023215 
2024205 
2025196 
2026191 
Thereafter1,938 
Future lease payments2,980 

28. CHANGES IN OPERATING ASSETS AND LIABILITIES

Year ended December 31,202120202019
(millions of Canadian dollars)   
Accounts receivable and other(1,228)1,546 (547)
Accounts receivable from affiliates(38)
Inventory(118)(254)(24)
Deferred amounts and other assets(195)(586)133 
Accounts payable and other(63)(770)63 
Accounts payable to affiliates52 (24)
Interest payable43 31 (41)
Other long-term liabilities(69)117 175 
 (1,616)93 (259)

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

We provide transportation services to several significantly influenced investees which we record as transportation and other services revenue. We also purchase and sell natural gas and crude oil with several of our significantly influenced investees. These revenues and costs are recorded as commodity sales and commodity costs. We contract for firm transportation services to meet our annual natural gas supply requirements which we record as gas distribution costs.

175


Our transactions with significantly influenced investees are as follows:

Year ended December 31,202120202019
(millions of Canadian dollars)
Transportation and other services149 133 140 
Commodity sales20 21 107 
Operating and administrative1
292 252 241 
Commodity costs2
790 518 773 
Gas distribution costs131 135 133 
1During the years December 31, 2021, 2020 and 2019, we had Operating and administrative costs from the Seaway Crude Pipeline System of $389 million, $342 million and $327 million, respectively. These costs are a result of an operational contract where we utilize capacity on Seaway Crude Pipeline System assets for use in our Liquids Pipelines business. The costs are offset by recoveries recorded on expenses incurred by us on behalf of our significantly influenced investees of $104 million, $94 million and $86 million for the years ended December 31, 2021, 2020 and 2019.
2During the years December 31, 2021, 2020 and 2019, we had Commodity costs from the Aux Sable Canada LP. of $447 million, $91 million and $272 million, respectively.

LONG-TERM NOTES RECEIVABLE FROM AFFILIATES
As at December 31, 2021, amounts receivable from affiliates include a series of loans totaling $954 million ($1,108 million as at December 31, 2020), which require quarterly or semi-annual interest payments at annual interest rates ranging from 3% to 8%. Interest income recognized from these notes totaled $39 million, $44 million and $40 million for the years ended December 31, 2021, 2020 and 2019, respectively. The amounts receivable from affiliates are included in Deferred amounts and other assets in the Consolidated Statements of Financial position.

30.  COMMITMENTS AND CONTINGENCIES

COMMITMENTS
As at December 31, 2021, we have commitments as detailed below:
Total
Less
than
1 year
2 years3 years4 years5 yearsThereafter
(millions of Canadian dollars)       
Annual debt maturities1
73,809 6,164 7,910 4,559 4,357 11,007 39,812 
Interest obligations2
36,044 2,531 2,389 2,229 2,073 1,925 24,897 
Purchase of services, pipe and other materials, including transportation3
7,876 2,945 1,010 736 561 607 2,017 
Maintenance agreements346 41 20 20 21 21 223 
Right-of-ways commitments1,249 35 35 35 36 37 1,071 
Total119,324 11,716 11,364 7,579 7,048 13,597 68,020 
1Includes 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.
2Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.
3Includes capital and operating commitments. Consists primarily of gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments.

176


ENVIRONMENTAL
We are subject to various Canadian and US federal, state and local laws relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us.

Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge and its affiliates are, at times, subject to environmental remediation at various sites where we operate. We manage this environmental risk through appropriate environmental policies, programs and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with our operating activities.

AUX SABLE
On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim.

On November 27, 2019, the counterparty filed an amended amended claim providing further particulars of its claim against Aux Sable, increasing its damages claimed, and adding defendants Aux Sable Liquid Products Inc. and Aux Sable Extraction LLC (general partners of the previously existing defendants). Aux Sable filed an amended Statement of Defence responding to the amended amended claim on January 31, 2020.

While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on our consolidated financial position or results of operations.

TAX MATTERS
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

OTHER LITIGATION
We and our subsidiaries are involved in various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.

31.  GUARANTEES
In the normal course of conducting business, we may enter into agreements which indemnify third parties and affiliates. We may also be a party to agreements with subsidiaries, jointly owned entities, unconsolidated entities such as equity method investees, or entities with other ownership arrangements that require us to provide financial and performance guarantees. Financial guarantees include stand-by letters of credit, debt guarantees, surety bonds and indemnifications. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Consolidated Statements of Financial Position. Performance guarantees require us to make payments to a third party if the guaranteed entity does not perform on its contractual obligations, such as debt agreements, purchase or sale agreements, and construction contracts and leases.

177


We typically enter into these arrangements to facilitate commercial transactions with third parties. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations, warranties or covenants, loss or damages to property, environmental liabilities, and litigation and contingent liabilities. We may indemnify third parties for certain liabilities relating to environmental matters arising from operations prior to the purchase or transfer of certain assets and interests. Similarly, we may indemnify the purchaser of assets for certain tax liabilities incurred while we owned the assets, a misrepresentation related to taxes that result in a loss to the purchaser or other certain tax liabilities related to those assets.

The likelihood of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We cannot reasonably estimate the total maximum potential amounts that could become payable to third parties and affiliates under such agreements described above; however, historically, we have not made any significant payments under guarantee or indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the guarantee or indemnification obligation, there are circumstances where the amount and duration are unlimited. As at December 31, 2021 guarantees and indemnifications have not had, and are not reasonably likely to have, a material effect on our financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources.

32.  QUARTERLY FINANCIAL DATA (UNAUDITED)
Q1Q2Q3Q4Total
(unaudited; millions of Canadian dollars, except per share amounts)
2021
Operating revenues12,187 10,948 11,466 12,470 47,071 
Operating income2,548 1,816 1,388 2,053 7,805 
Earnings2,014 1,521 814 1,965 6,314 
Earnings attributable to controlling interests1,992 1,484 780 1,933 6,189 
Earnings attributable to common shareholders1,900 1,394 682 1,840 5,816 
Earnings per common share
Basic0.94 0.69 0.34 0.91 2.87 
Diluted0.94 0.69 0.34 0.91 2.87 
2020
Operating revenues12,013 7,956 9,110 10,008 39,087 
Operating income1,513 2,098 2,095 2,251 7,957 
Earnings/(loss)(1,364)1,777 1,104 1,899 3,416 
Earnings/(loss) attributable to controlling interests(1,333)1,741 1,084 1,871 3,363 
Earnings/(loss) attributable to common shareholders(1,429)1,647 990 1,775 2,983 
Earnings/(loss) per common share
Basic(0.71)0.82 0.49 0.88 1.48 
Diluted(0.71)0.82 0.49 0.88 1.48 

178


ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES
DISCLOSURE CONTROLS AND PROCEDURES
Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and US securities law. As at December 31, 2021, an evaluation was carried out under the supervision of and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

INTERNAL CONTROL OVER FINANCIAL REPORTING
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in the rules of the SEC and the Canadian Securities Administrators. Our internal control over financial reporting is a process designed under the supervision and with the participation of executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes in accordance with US GAAP.

Our internal control over financial reporting includes policies and procedures that:
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets;
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with US GAAP; and
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.
Our internal control over financial reporting may not prevent or detect all misstatements because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with our policies and procedures.
Our management assessed the effectiveness of our internal control over financial reporting as at December 31, 2021, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our management concluded that we maintained effective internal control over financial reporting as at December 31, 2021.

179


The effectiveness of our internal control over financial reporting as at December 31, 2021 has been audited by PricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm appointed by our shareholders. As stated in their Report of Independent Registered Public Accounting Firm which appears in Item 8.Financial Statements and Supplementary Data, they expressed an unqualified opinion on the effectiveness of our internal control over financial reporting as at December 31, 2021.

Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2021, there has been no material change in our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

NORMAL COURSE ISSUER BID

On December 31, 2021, we announced that the TSX had approved our NCIB to purchase, for cancellation, up to 31,062,331 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion, subject to certain restrictions on the number of common shares that may be purchased on a single day.

Purchases under the NCIB may be made through the facilities of the TSX, the NYSE and other designated exchanges and alternative trading systems, commencing on January 5, 2022 and continuing until January 4, 2023, when the bid expires, or such earlier date on which Enbridge has either acquired the maximum number of common shares allowable under the NCIB or otherwise decide not to make any further repurchases under the NCIB. The maximum number of common shares that Enbridge may repurchase for cancellation represents approximately 1.53% of the 2,026,085,179 common shares issued and outstanding as at December 22, 2021.

A copy of our notice of intention to make a normal course issuer bid may be obtained, free of charge, by contacting Investor Relations by email, phone or mail at:

Email:investor.relations@enbridge.com
Phone Within North America: 1-800-481-2804
Phone Outside North America: 1-403-231-3960
Mail: Enbridge Inc. Investor Relations, 200, 425 – 1st Street S.W., Calgary, Alberta, Canada T2P 3L8

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.
180


PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors of Registrant
The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than 120 days after December 31, 2021. This information will also be disclosed in the management proxy information that we prepare in accordance with Canadian corporate and securities law requirements.

Executive Officers of Registrant
The information regarding executive officers is included in Part I. Item 1. Business - Executive Officers.

Code of Ethics for Chief Executive Officer and Senior Financial Officers
The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than 120 days after December 31, 2021. This information will also be disclosed in the management proxy information that we prepare in accordance with Canadian corporate and securities law requirements.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than 120 days after December 31, 2021. This information will also be disclosed in the management proxy information that we prepare in accordance with Canadian corporate and securities law requirements.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Equity Compensation Plan Information
SeeThe information required by this Item 11 – “Shares reserved for equity compensation as ofwill be disclosed in our Form 10-K/A, which will be filed no later than 120 days after December 31, 2020” for2021. This information regarding our equity plan compensation on page 51.
Security ownership of certain beneficial owners and management
Beneficial ownership table
The table below sets forth the number and percentage of outstanding Enbridge shares beneficially owned by each of our Directors, each of our NEOs and all Directors and executive officers as a group, as of March 2, 2021. The number of Enbridge shares beneficially owned by each person is determined under applicable SEC rules. Under these rules, a person is deemed to have “beneficial ownership” of any shares over which that person, directly or indirectly, has or shares voting or investment power, plus any shares that the person has the right to acquire within 60 days, including through the exercise of stock options. Unless otherwise indicated, for each person namedwill also be disclosed in the table, the numbermanagement proxy information that we prepare in the “Number of Enbridge shares acquirable within 60 days” column includes shares covered by stock options that may be exercisedaccordance with Canadian corporate and that vest within 60 days after March 2, 2021. Unless otherwise indicated in the table, the address of each of the individuals below is c/o Enbridge Inc., 200, 425 - 1st Street SW, Calgary, Alberta, T2P 3L8.
securities law requirements.
Name of beneficial owner
  
Number of
Enbridge shares
held
   
Number of
Enbridge shares
acquirable within
60 days
   
Total
Enbridge shares
beneficially owned
   
Percent of
common shares
outstanding
 
Pamela L. Carter
   44,639    
-
1
    44,639    * 
Marcel R. Coutu
   46,900    -    46,900    * 
Susan M. Cunningham
   2,581    -    2,581    * 
Gregory L. Ebel
   651,845    405,408    1,057,253    * 
J. Herb England
   37,306    
-
1
    37,306    * 
Gregory J. Goff
   -    -    -    * 
V. Maureen Kempston Darkes
   21,735    -    21,735    * 
Teresa S. Madden
   1,000    -    1,000    * 
Al Monaco
   920,699    2,832,230    3,752,929    * 
Stephen S. Poloz
   -    -    -      
Dan C. Tutcher
   637,523    -    637,523    * 
Colin K. Gruending
   59,432    489,859    549,291    * 
Robert R. Rooney
   48,656    378,596    427,252    * 
William T. Yardley
   122,012    386,016    508,028    * 
Vern D. Yu
   164,753    718,808    883,561    * 
John K. Whelen
   204,203    887,450    1,091,653    * 
All current executive officers and directors as a group
2
   3,083,199    6,824,589    9,907,788    * 
1
Ms. Carter and Mr. England will be paid a portion of their directors’ compensation in Enbridge shares on March 19, 2021. Under our Directors’ Compensation Plan, the number of Enbridge shares will be calculated by dividing the applicable amount of compensation in Canadian dollars payable in Enbridge shares on the payment date by the weighted average the closing price per Enbridge share on the TSX for the five trading days prior to the date that is two weeks prior to the payment date.
2
Mr. Whelen’s security ownership is not included in this total as he retired effective November 15, 2020.
*
Represents less than 1% of the outstanding Enbridge shares.
Principal shareholders
As of March 2, 2021, there are no persons known to Enbridge who beneficially own more than five percent of issued and outstanding Enbridge shares.
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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Handling conflicts of interest and related person transactions
If a director or officer has a material interestThe information required by this Item will be disclosed in a transaction or agreement involving Enbridge, or otherwise identifies a potential personal conflict, he or she must:
declare the conflict or potential conflict; and
abstain from voting on the matter at any Board meeting where it is being discussed or considered.
our Form 10-K/A, which will be filed no later than 120 days after December 31, 2021. This approach is consistent with the requirements of the CBCA. In addition, the Board would review related person transactions in conjunction with making director independence determinations. Completion of annual questionnaires by directors and officers of the company assists in identifying possible related person transactions. Further, as stated above, pursuant to our Statement on Business Conduct, all officers and directors are required to avoid conflicts of interest and to disclose any actual or potential conflicts of interest. They mustinformation will also annually certify their compliance with the Statement on Business Conduct. Disclosures of an actual or potential conflict of interest are reviewed by the company’s Ethics & Compliance Department to ensure appropriate
follow-up
and reporting. Any waiver from any part of the Statement on Business Conduct requires the approval of the CEO. For executive officers, senior financial officers and members of the Board, a waiver requires the express approval of Enbridge’s Board. Since the beginning of 2020, neither the CEO nor the Board has waived any aspect of the Statement on Business Conduct.
For purposes of the foregoing, a “related person transaction” is a transaction in which the company was or is to be a participant and the amount involved exceeds US$120,000, and in which any related person had or will have a direct or indirect material interest, and a “related person” means (i) a director, nominee director or executive officer of the company; (ii) an immediate family member of a director, nominee director or executive officer, or (iii) a beneficial holder of greater than five per cent of the company’s shares or an immediate family member of such holder.
Interest of informed person in material transaction
On February 27, 2017, Enbridge and Spectra Energy combined through a
stock-for-stock
merger transaction (the “Merger Transaction”). Upon the closing of the Merger Transaction, Gregory L. Ebel (Spectra Energy’s former Chairman, President and CEO) became the
non-executive
Chair of the Enbridge Board. Enbridge was required, until the first meeting of the Board following the 2020 annual meeting of shareholders of Enbridge:
to provide, without charge, to Mr. Ebel as
non-executive
Chair: (i) use of Enbridge’s aircraft for business flights to Board meetings and for other business conducted on behalf of Enbridge, (ii) information technology support and (iii) administrative support; and
to secure office spacedisclosed in the Houston area on behalf of Mr. Ebelmanagement proxy information that we prepare in accordance with Canadian corporate and to reimburse thesecurities law requirements.
non-executive
Chair for expenses incurred for tax return preparation services (in an aggregate amount not to exceed US$100,000 per year for such office and tax return preparation services).

Pursuant to the merger agreement relating to the Merger Transaction, the foregoing requirements ended in July 2020.
Independence
The majority of our directors must be independent, as defined by Canadian securities regulators in NI
52-110,
NYSE rules and the rules and regulations of the SEC. Our Governance Guidelines, available on our website (www.enbridge.com), provide that the Board shall consist of a substantial majority of independent directors. The Board uses a detailed annual questionnaire to assist in determining if a director is independent and makes this determination annually or more often, if required.
The Board has determined that 10 of our 11 directors, including the Chair of the Board, are independent. Mr. Monaco is not independent because he is our President & CEO. With respect to former directors who served as directors during any part of 2020, Charles W. Fischer and Catherine L. Williams were also independent.
The Governance Committee is responsible for ensuring the Board functions independently of management. The Governance Committee has developed guidelines to ensure each director is aware of the expectations placed on them as a director. Key expectations include meeting attendance, financial literacy and ethical conduct.
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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than 120 days after December 31, 2021. This information will also be disclosed in the management proxy information that we prepare in accordance with Canadian corporate and securities law requirements.

External auditor services – fees
The following table sets forth all services rendered by the company’s auditors, PwC, by category, together with the corresponding fees billed by the auditors for each category of service for the financial years ended December 31, 2020 and 2019.
    
2020
(C$)
  
2019
(C$)
  
Description of fee category
Audit fees
  14,764,000  16,928,000  Represents the aggregate fees for audit services.
Audit-related fees
  816,000  431,000  Represents the aggregate fees for assurance and related services by the company’s auditors that are reasonably related to the performance of the audit or review of the company’s financial statements and are not included under “Audit fees”. During fiscal years 2020 and 2019, the services provided in this category include services related to prospectus offerings.
Tax fees
  1,417,000  1,993,000  Represents the aggregate fees for professional services rendered by the company’s auditors for tax compliance, tax advice and tax planning.
All other fees
  366,000  320,000  Represents the aggregate fees for products and services provided by the company’s auditors other than those services reported under “Audit fees”, “Audit-related fees” and “Tax fees”. During fiscal years 2020 and 2019, these fees include those related to French translation work.
Total fees
  17,363,000  19,672,000   
Pre-approval
policies and procedures
The Audit, Finance & Risk Committee has adopted a policy that requires
pre-approval
by the Audit, Finance & Risk Committee of any services to be provided by the company’s external auditors, PwC, whether audit or
non-audit
services. The policy prohibits the company from engaging the auditors to provide the following
non-audit
services:
bookkeeping or other services related to accounting records and financial statements;
financial information systems design and implementation;
appraisal or valuation services, fairness opinions or contribution in kind reports;
actuarial services;
internal audit outsourcing services;
management functions or human resources;
broker or dealer, investment adviser or investment banking services;
legal services; and
expert services unrelated to the audit.
The Audit, Finance & Risk Committee believes that the policy will protect the company from the potential loss of independence of the external auditors. The Audit, Finance & Risk Committee has also adopted a policy which prohibits the company from hiring (as a full time employee, contractor or otherwise) into a financial reporting oversight role any current or former employee or partner of its external auditor who provided audit, review or attest service in respect of the company’s financial statements (including financial statements of its reporting issuer subsidiaries and significant investees) during the 12 month period preceding the date of the initiation of the current annual audit. The policy further prohibits the hiring of a former partner of the company’s external auditor who receives pension benefits from the firm, unless such pension benefits are of a fixed amount, not dependent upon firm earnings and fully funded. In all cases, the hiring of any partner or employee or former partner or employee of the independent auditor is subject to joint approval by the lead engagement partner and the company’s Senior Vice President and Chief Accounting Officer.
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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Consolidated Financial Statements, Supplemental Financial Data and Supplemental Schedules included in Part IV (Item 15)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 Original FilingConsolidated Financial Statements

All schedules are omitted because they are not required or because the required information is hereby amended solely to addincluded in the following exhibits required to be filed in connection with this Amendment No. 1.
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.

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Table of Contents

INDEX OF EXHIBITS

Each exhibit identified below is included as a part of this Amendment No. 1.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 Articles of Continuance of the Corporation, dated December 15, 1987 (incorporated by reference to Exhibit 2.1(a) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.2 Certificate of Amendment, dated August 2, 1989, to the Articles of the Corporation (incorporated by reference to Exhibit 2.1(b) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.3 Articles of Amendment of the Corporation, dated April 30, 1992 (incorporated by reference to Exhibit 2.1(c) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.4 Articles of Amendment of the Corporation, dated July 2, 1992 (incorporated by reference to Exhibit 2.1(d) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.5 Articles of Amendment of the Corporation, dated August 6, 1992 (incorporated by reference to Exhibit 2.1(e) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.6 Articles of Arrangement of the Corporation dated December 18, 1992, attaching the Arrangement Agreement, dated December 15, 1992 (incorporated by reference to Exhibit 2.1(f) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.7 Certificate of Amendment of the Corporation (notarial certified copy), dated December 18, 1992 (incorporated by reference to Exhibit 2.1(g) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.8 Articles of Amendment of the Corporation, dated May 5, 1994 (incorporated by reference to Exhibit 2.1(h) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.9 Certificate of Amendment, dated October 7, 1998 (incorporated by reference to Exhibit 2.1(i) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.10 Certificate of Amendment, dated November 24, 1998 (incorporated by reference to Exhibit 2.1(j) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
3.11 Certificate of Amendment, dated April 29, 1999 (incorporated by reference to Exhibit 2.1(k) to Enbridge’s Registration Statement on Form S-8 filed May 7, 2001)
183


*
184



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.
31.1*
185


+
+
+
+
+
+

+
+
+
+
+

+

186


+

+
+
+
+
+
+
+
+
+
+
+
+
+
+
187


+
+
+
+
+
+
+
*
*
*
*
31.2**
*
104**
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 DataDate File (embedded– the cover page XBRL tags are embedded within the Inline XBRL document)document (included in Exhibit 101).

70
188

Each person whose signature appears below appoints Robert R. Rooney, Vern D. Yu and Karen K. L. Uehara, and each of Contentsthem, 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.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENBRIDGE INC.
(Registrant)
Date:February 11, 2022By:/s/ Al Monaco
Al Monaco
President and Chief Executive Officer

189


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 11, 2022 by the following persons on behalf of the registrant and in the capacities indicated.

ENBRIDGE INC.
(Registrant)
Date: March 8, 2021/s/ Al Monaco/s/ Vern D. Yu
Al Monaco
President, Chief Executive Officer and Director
(Principal Executive Officer)
By:
/s/ Colin K. GruendingVern D. Yu
Colin K. Gruending
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
/s/ Patrick R. Murray/s/ Gregory L. Ebel
Patrick R. Murray
Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)
Gregory L. Ebel
Chairman of the Board of Directors
/s/ Mayank (Mike) M. Ashar/s/ Gaurdie E. Banister
Mayank (Mike) M. Ashar
Director
Gaurdie E. Banister
Enbridge Inc.
Director
/s/ Pamela L. Carter/s/ Susan M. Cunningham
Pamela L. Carter
Director
Susan M. Cunningham
Director
/s/ J. Herb England/s/ Teresa S. Madden
J. Herb England
Director
Teresa S. Madden
Director
/s/ Stephen S. Poloz/s/ S. Jane Rowe
Stephen S. Poloz
Director
S. Jane Rowe
Director
/s/ Dan C. Tutcher
Dan C. Tutcher
Director

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