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Table of Contents

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

FORM
10-K/A
Amendment No. 1
FORM10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20202023
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from
to
Commission file number001-15254

1-10934
ENBRIDGE INC.
(Exact Name of Registrant as Specified in Its Charter)

Canada98-0377957
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)
(403) 231-3900
(Registrant’s telephone number, including area code (403)
231-3900Telephone Number, Including Area Code)

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
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, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company”company,” and “emerging"emerging growth company”company" in Rule
12b-2
of the Exchange Act.
Large accelerated filerAccelerated filer
Large Accelerated FilerNon-accelerated filerAccelerated Filer
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
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to § 240.10D-1(b).
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No
The aggregate market value of the registrant’s common shares held by
non-affiliates
computed by reference to the price at which the common equity was last sold on June 30, 2020,2023, was approximately US$59.275.1 billion.
As at February 5, 2021,2, 2024, the registrant had 2,025,495,6032,125,586,356 common shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:
Not applicable.


EXPLANATORY NOTE

Enbridge Inc., a corporation existing under the
Canada Business Corporations Act
, qualifies as a foreign private issuer in the United States (US) for purposes of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)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 proxyinformation circular and related material under Canadian requirements. As Enbridge Inc.’s management proxyinformation 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 proxyinformation 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 inno later than 120 days after the Original Filing.
end of the fiscal year covered by this Form 10-K.
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, other 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
GLOSSARY
DIRECTORS OF REGISTRANT

Director profiles
Shareholders elect directors to the Board for a term of one year, expiring at 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.
 
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

 
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
"we", "our", "us" and "Enbridge"
Percentages are rounded to the nearest whole number.
Enbridge Inc.
2
AFUDC
Ms. Carter was appointed to the Human Resources & Compensation Committee on May 4, 2020.
Allowance for funds used during construction
3
Aitken Creek
Information about beneficial
Aitken Creek Gas Storage Facility and Aitken Creek North Gas Storage Facility
AOCIAccumulated other comprehensive income/(loss)
AROAsset retirement obligations
ASCAccounting Standards Codification
Aux SableUS Midstream ownership and about securities controlled or directed was provided by the director nominees and is as at March 2, 2021.interest in Aux Sable Liquid Products LP, Aux Sable Midstream LLC, Aux Sable Canada LP
4
BC
DSUs refer to deferred share units and are defined on page 59
British Columbia
bcf/dBillion cubic feet per day
CE RegulationClean Electricity Regulation
CERCanada Energy Regulator
CTSCompetitive Toll Settlement
DAPLDakota Access Pipeline
DawnAn extensive network 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 meetingsunderground storage pools 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 CommitteeTecumseh Gas Storage facility and the Safety & Reliability Committee on July 22, 2020.
13

Director independence
Dawn Hub
DCPDCP Midstream, LP
  Name
EBITDA
Independent
Not independent
Reason for non-independence
Earnings before interest, income taxes and depreciation and amortization
EEPEnbridge Energy Partners, L.P.
  Gregory L. Ebel (Chair)
EIEC
Enbridge Ingleside Energy Center
Enbridge GasEnbridge Gas Inc.
  Pamela L. Carter
ESG
Environment, Social and Governance
Exchange Act
  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.United States Securities Exchange Act of 1934
FERCFederal Energy Regulatory Commission
GHGGreenhouse gas
Gray OakGray Oak Pipeline, LLC
H2Hydrogen gas
IJTInternational Joint Tariff
IRIncentive Regulation
ISOIncentive Stock Options
kbpdThousand barrels per day
LMCILand Matters Consultation Initiative
LNGLiquefied natural gas
M&NMaritimes & Northeast Pipeline
4


,
as amended.
M&N CanadaCanadian portion of our Maritimes & Northeast Pipeline
ModaModa Midstream Operating, LLC
MTSMainline Tolling Settlement
MWMegawatts
NCIBNormal course issuer bid
NEXUSNEXUS Gas Transmission Pipeline
NGLNatural gas liquids
NovercoNoverco Inc.
OBPSOutput-based pricing system
OCIOther comprehensive income/(loss)
OEBOntario Energy Board
OPEBOther postretirement benefit obligations
Phase 1Phase to establish 2024 base rates on a cost-of-service basis
Phase 1 DecisionOn December 21, 2023, the Ontario Energy Board issued its Decision and Order on Phase 1
PPAPower purchase agreement
PSUPerformance Stock Units
RNGRenewable natural gas
ROURight-of-use
RSURestricted Stock Units
SECUS Securities and Exchange Commission
SEPSpectra Energy Partners, LP
Spectra EnergySpectra Energy Corp
Texas EasternTexas Eastern Transmission, LP
TGETri Global Energy, LLC
the AcquisitionsOn September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina
the BoardBoard has also determined thatof Directors
the Lakehead System SettlementOn May 24, 2023, Enbridge filed an Offer of Settlement with the Federal Energy Regulatory Commission for the Lakehead System
the Moda AcquisitionOn October 12, 2021, through a wholly-owned US subsidiary, we acquired all members of the Audit, Finance & Risk Committee are financially literate according to outstanding membership interests in Moda Midstream Operating, LLC
the meaningPartnershipsSpectra Energy Partners, LP and Enbridge Energy Partners, L.P.
Tres PalaciosTres Palacios Holdings LLC
TSXToronto Stock Exchange
UKThe United Kingdom
USUnited States of National Instrument
52-110
Audit Committees
andAmerica
US GAAPGenerally accepted accounting principles in the rulesUnited States of the NYSE.America
3
Vector
Ms. Cunningham was appointed as Chair of the Corporate Social Responsibility Committee on May 4, 2020.
Vector Pipeline L.P.
4
VIEs
Ms. Kempston Darkes was appointed as Chair of the Human Resources & Compensation Committee on May 4, 2020.
Variable interest entities
WestcoastWestcoast Energy Inc.
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 skillsUnless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to "dollars" or "$" are to Canadian dollars and experience
We maintain a skills and experience matrix for our directors in areas we thinkall references to "US$" 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 basedUS dollars. All amounts are provided on a self-assessment by each director.
before-tax basis, unless otherwise stated.
  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
;

FORWARD-LOOKING INFORMATION
requirements of the CBCA; and

the corporate governance guidelines of the NYSE.
STATEMENT ON BUSINESS CONDUCT
Our StatementForward-looking information, or forward-looking statements, have been included in this Annual Report on Business Conduct (available on our website at www.enbridge.com) is our formal statement of expectations that appliesForm 10-K to all individuals at Enbridgeprovide information about us and our subsidiaries and affiliates, including management’s assessment of our directors, officers, employees, contingent workersand 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 well as consultants‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and contractors retainedsimilar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by Enbridge. It discusses what we expectreference in various areas including:
complyingthis document include, but are not limited to, statements with respect to the law, applicable rulesfollowing: our corporate vision and all policies;
avoiding conflictsstrategy, including strategic priorities and enablers; expected supply of, interest, including examplesdemand for, exports of acceptable formsand prices of giftscrude oil, natural gas, natural gas liquids (NGL), liquefied natural gas (LNG) and entertainment;
anti-corruptionrenewable energy; energy transition and money laundering;
acquiring, usinglower-carbon energy, and maintaining assets (including computersour approach thereto; environmental, social and communication devices) appropriately;
data privacy, records management,governance (ESG) goals, practices and proprietary, confidentialperformance; industry and insider information;
protecting health, safetymarket conditions; anticipated utilization of our assets; dividend growth and the environment;
interacting with landowners, customers, shareholders, employeespayout policy; financial strength and others;flexibility; expectations on sources of liquidity 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 sufficiency of employment with Enbridgefinancial resources; expected strategic priorities 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 throughGeneration and Energy Services businesses; the enhancementcharacteristics, anticipated benefits, financing and timing of existing asset returns, along with prudent investment in new
in-franchise
our acquisitions of three US gas utilities (Gas Utilities) from Dominion Energy, Inc. (the Acquisitions); expected costs, benefits and in-service dates related to announced projects and projects under construction; expected capital expenditures; investable capacity and capital efficient organicallocation priorities; expected equity funding requirements for our commercially secured growth program; expected future growth, development and expansion opportunities; expected optimization and efficiency opportunities; expectations about our joint venture partners’ ability to complete and finance projects that fitunder construction; expected closing of acquisitions and dispositions and the timing thereof, including the Acquisitions; expected benefits of transactions, including the Acquisitions; our lowability to complete the Acquisitions and successfully integrate the Gas Utilities; expected future actions of regulators and courts, and the timing and impact thereof; toll and rate cases discussions and proceedings and anticipated timeline and impact therefrom, including Mainline Contracting and those relating to the Gas Distribution and Storage and Gas Transmission and Midstream businesses; operational, industry, regulatory, climate change and other risks associated with our businesses; and our assessment of the potential impact of the various risk pipeline-utility model. Atfactors identified herein.

Although we believe these forward-looking statements are reasonable based on the foundationinformation available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of, demand for, export of and prices of crude oil, natural gas, NGL, LNG and renewable energy; anticipated utilization of assets; exchange rates; inflation; interest rates; availability and price of labor and construction materials; the stability of our strategic plan is a continued focus onsupply chain; operational reliability; maintenance of support and regulatory approvals for our projects and transactions; anticipated in-service dates; weather; the safetiming, terms and reliable transportationclosing of energy to end use markets, which is always our number one priority.
We delivered strong results driven by solid operating performance acrossacquisitions and dispositions, including the entire asset base despiteAcquisitions; the unprecedentedrealization of anticipated benefits of transactions, including the Acquisitions; governmental legislation; litigation; estimated future dividends and 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 focusdividend policy on our people,future cash flows; our credit ratings; capital project funding; hedging program; expected earnings before interest, income taxes, and depreciation and amortization (EBITDA); expected earnings/(loss); expected future cash flows; and expected distributable cash flow. Assumptions regarding the communitiesexpected supply of and demand for crude oil, natural gas, NGL, LNG and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our shareholders.services and cost of inputs, and are therefore inherent in all forward-looking statements. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects
6


The
COVID-19
crisis has taken an unprecedented humanunder construction, including estimated completion dates and economic toll. As a company that employs thousandsexpected capital expenditures, include the following: the availability and price of people across hundreds of communities,labor and that safely delivers affordable, reliable energy that fuels quality of life for millions, we take our responsibility to be resilient inconstruction materials; the servicestability of our shareholders seriously.
supply chain; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.

From the outset of the pandemic, Enbridge’s priority has beenOur forward-looking statements are subject to protect its employees, their familiesrisks 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 responseuncertainties pertaining 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 $1.6 billion of secured growth projects, including the final phase of Atlantic Bridge, Sabal Trail Phase II, the 2020 Modernization Program within Gas Transmission and Midstream, and the 2020 Utility Growth Program, including the Owen Sound Reinforcement and Windsor Line Replacement projects
1
DCF per share is a
non-GAAP
measure; this measure is defined and reconciled in Item 11 –
“Non-GAAP
reconciliation”.
2020 project successful execution
Project
Expected ISD
Capital ($B)
1
Gas Transmission and Midstream
Sabal Trail Phase II
In-service
US$0.1
2020 Modernization Program
In-service
US$0.7
Gas Distribution and Storage
2020 Utility Growth Program
In-service
0.5
2020 Total
1.6
1
U.S. dollars have been converted to Canadian dollars using an exchange rate of US$1 = C$1.30.
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

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 prioritiespriorities; operating performance; legislative and are designedregulatory parameters; litigation; acquisitions (including the Acquisitions), dispositions and other transactions and the realization of anticipated benefits therefrom; operational dependence on third parties; dividend policy; project approval and support; renewals of rights-of-way; weather; economic and competitive conditions; public opinion; changes in tax laws and tax rates; exchange rates; inflation; interest rates; commodity prices; access to link payoutsand cost of capital; political decisions; global geopolitical conditions; and the supply of, demand for and prices of commodities and other alternative energy, including but not limited to, those outcomes. They motivate management to deliver exceptional value to Enbridge stakeholders through strong corporate performancerisks 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 standarduncertainties discussed in this Amendment No. 1Annual Report on Form 10-K/A.10-K and in our other filings with Canadian and US securities regulators. 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 workimpact of any compensation consultants, outside legal counselone assumption, risk, uncertainty or other advisors it retains (each, an “Advisor”). The HRC Committee may select or receive advice from an Advisor only after taking into considerationfactor 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 factorsinformation available at the relevant time. Except to the Advisor’s independence from management including:
the provision of other servicesextent required by applicable law, Enbridge assumes no obligation 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;
publicly update or revise any shares owned by the Advisor; and
any businessforward-looking statement made in this Annual Report on Form 10-K 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, consideringotherwise, 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
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.
Type of termination
Base salary
Short-term incentive
Medium- and long-term incentives
Pension
Benefits

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.None
RetirementCurrent 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.

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).
Termination following a change of control (CIC)
•  PSUs vest 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).
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, assumednew information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to occur as of December 31, 2020. The actual amounts that would be payableus or persons acting on our behalf, are expressly qualified in their entirety by 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.
cautionary statements.
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

NON-GAAP AND OTHER FINANCIAL MEASURES
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
Enbridge shares reserved for issue under the 2019 LTIP
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.
Enbridge shares that can be issued in a
one-year
period
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)
The number of Enbridge shares that can be issued as incentive stock options (within the meaning of the U.S. Internal Revenue Code)Up to 2,000,000 Enbridge shares can be issued under the 2019 LTIP as incentive stock options.
Stock options delivered to a greater than 10% shareholderIf 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.
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.
Reason for termination
Incentive stock option provisions
1
Restricted stock unit provisions
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
Incentive stock option provisions
1
Restricted stock unit provisions
Change of control or
reorganization
Beginning with the 2017 grants, 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 unvested options 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.
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”)Part II. 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.
  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 CompensationItem 7. Management’s Discussion and Analysis with management. Basedof Financial Condition and Results of Operations (MD&A) in this Annual Report on the reviewForm 10-K makes reference to non-GAAP and discussion, the Human Resources & Compensation Committee recommendedother financial measures, including EBITDA. EBITDA is defined as earnings before interest, income taxes and depreciation and amortization. Management uses EBITDA 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
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.
59

We expect directors to own Enbridge shares so they have an ongoing stake in the company and are aligned with 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$242,250 and the director share ownership requirement since June 1, 2020 was US$726,750. Effective April 1, 2021, the director share ownership requirement will increase to US$855,000.
If a decrease in the market value of Enbridge shares results in a director no longer meeting the share ownership requirements, we expect him or her to buy additional Enbridge shares in order to satisfy the minimum threshold.
DSUs are paid out when a director retires from the Board. They are settled in cash, based on the weighted average of the trading price of common shares on the TSX for the last five trading days 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 securities 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.
60

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.
61

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.
62

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
63

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.
64

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.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 the accounting principles 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.sedarplus.ca or www.sec.gov.
7


PART I

ITEM 1. BUSINESS

Enbridge is a leading North American energy infrastructure company. Our core businesses include Liquids Pipelines, which consists of pipelines and terminals in Canada and the US that transport and export various grades of crude oil and other liquid hydrocarbons; Gas Transmission and Midstream, which consists of investments in natural gas pipelines and gathering and processing facilities in Canada and the US; Gas Distribution and Storage, which consists of natural gas utility operations that serve residential, commercial and industrial customers in Ontario and Québec; and Renewable Power Generation, which consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery and transmission assets, in North America and Europe.

Enbridge is a public company, with common shares that trade on the Toronto Stock Exchange (TSX) and New York Stock Exchange (NYSE) under the symbol ENB. We were incorporated on April 13, 1970 under the Companies Ordinance of the Northwest Territories and were continued under the Canada Business Corporations Act on December 15, 1987.

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

CORPORATE VISION AND STRATEGY

VISION
Enbridge exists to fuel people’s quality of life in a safe, clean, and socially responsible manner. Our vision is to provide energy, in a planet-friendly way, everywhere people need it. In pursuing this vision, we seek to play a critical role in enabling the economic and social well-being of society by providing access to affordable, reliable, and secure energy through our infrastructure franchises that transport, distribute, and generate energy including liquids, natural gas, renewable power, and low-carbon fuels. We recognize that the energy system is changing, and we aim to provide a bridge to a cleaner energy future by ensuring that people continue to have access to the energy they need today while investing in the lower-carbon platforms that will sustain us going forward.

Our leading 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 as well as targeted areas of growing renewable and new energy demand. Our assets are underpinned by long-term contracts, regulated cost-of-service tolling frameworks, power purchase agreements (PPAs), and other low-risk commercial arrangements.

Everyday, we strive to be the first-choice energy delivery company in North America and beyond—for customers, communities, investors, regulators, policymakers, and employees. We approach this goal with a focus on worker and public safety, ESG leadership, stakeholder relations, community investment, and employee engagement.

STRATEGY
Our strategy is underpinned by a deep understanding of energy supply and demand fundamentals. Through disciplined capital allocation, which is aligned with our outlook on energy markets, we have become an industry leader with a diversified portfolio across both conventional and lower-carbon energies. Our assets have reliably generated low-risk, resilient cash flows through many different commodity, economic, and geopolitical environments. We believe that our asset quality and diversity are key differentiators that allow us to be flexible in an uncertain business environment.
8


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

Predictable cash flows and ratable growth are hallmarks of our investor value proposition. Our robust portfolio of project development opportunities, the integration of recent strategic acquisitions, and ongoing efficiency improvements are expected to drive our growth in the near term (2024-2025) and the medium term to come. We remain confident in our balanced growth strategy and expect to continue to selectively invest in our diversified footprint of both conventional businesses and complementary lower-carbon platforms, such as renewable power, renewable natural gas (RNG), carbon capture and storage (CCS), blue ammonia, and hydrogen gas (H2). Additionally, ESG continues to be integral to our strategy; we are committed to reducing our emissions, building lasting relationships with our stakeholders, and promoting diversity, equity, and inclusion.

In alignment with our strategy, we progressed several of our priorities in 2023. For example:

We announced the strategic acquisition of three US gas utilities in Ohio, Utah, and North Carolina. If completed, the Acquisitions will create the largest natural gas utility franchise in North America, lower our already industry-leading business risk profile, and secure visible, low-risk, long-term, rate base growth.

Our Liquids Pipelines business delivered record volumes on the Mainline and Permian systems, exported record volumes through our Enbridge Ingleside Energy Center (EIEC), reached a tolling agreement for the Mainline system, sanctioned the Enbridge Houston Oil Terminal, assumed operatorship of Gray Oak Pipeline (Gray Oak), and advanced contracting open seasons for the Flanagan South Pipeline (Flanagan South), Gray Oak and Southern Lights pipelines, further strengthening our premier heavy and light oil delivery and export system.

Our Gas Transmission and Midstream business acquired Aitken Creek Gas Storage facility and Aitken Creek North Gas Storage facility (collectively, Aitken Creek) in British Columbia and Tres Palacios Holdings LLC in Texas, achieved a final investment decision on the Rio Bravo Pipeline, advanced the Woodfibre LNG Project, and have been successfully executing on open seasons for both the Algonquin pipeline and Texas Eastern Transmission line. We continue to capitalize on strong gas fundamentals to deliver safe, reliable, and sustainable energy to North Americans while simultaneously growing LNG exports.

Within our existing Gas Distribution and Storage business, we have progressed our rate rebasing application in Ontario, added over 46,000 new customers, and advanced Ontario’s largest greenhouse gas (GHG) reduction project to shift Arcelor Mittal’s steel-making operations from coal to natural gas. We continue to fuel Ontarians’ quality of life and economic growth through providing cost-effective, reliable, and sustainable energy to the province.

Our Renewable Power Generation business continues to execute its growth strategy with significant progress on our European offshore wind portfolio including a 1,000 megawatt (MW) project award for the Normandy (Centre Manche 1) project in France, increased working interest at the Hohe See and Albatros projects in Germany, and ongoing construction of three additional projects in France. Our North American onshore business continued its growth through the ongoing advancement of our large development portfolio (currently greater than 4,500 MW) and through the investment in the Fox Squirrel solar project in Ohio.

9


Our New Energy Technologies team, in collaboration with each business unit, advanced our low-carbon strategy through the acquisition of Morrow Renewables’ RNG assets, the creation of a strategic partnership with Yara to progress a blue ammonia export project at our EIEC near Corpus Christi, Texas, the sanctioning of the Longview RNG Project in Washington state with Divert Inc., and the continued development of prioritized lower-carbon technologies.

We have made meaningful progress towards our ESG goals this year. We have continued to strengthen our relationships with Indigenous communities across North America while advancing our reconciliation commitments. We also increased the diversity of our Board and workforce. We are continuing on our path to net zero by lowering our emissions with multiple levers including system modernization, methane reduction technologies, powering our operations with cleaner-energy sources, and continued investment in our lower-carbon businesses.

We continue to recycle capital at attractive valuations and in 2023 this included the announced sale of our interests in the Alliance Pipeline and Aux Sable facility. We remain focused on disciplined capital allocation, portfolio optimization and diversification, the continued enhancement of our industry leading cash flow profile, and financial strength and flexibility. In addition, we continue to prioritize operating cost reductions to increase our profitability and competitiveness.

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

Looking ahead, our near-term strategic priorities remain similar to years past. As always, proactively advancing the safety of our assets, protecting the environment, and maintaining the reliability of our system remain our top priorities. We are focused on enhancing the value of our existing assets through further optimization, capitalizing on our extensive infrastructure to meet evolving customer needs, prioritizing in-franchise organic growth and export-driven opportunities, and developing lower-carbon platforms across all our businesses. We will continue to invest where we can advance our strategy, build sustainable competitive advantage, and achieve attractive risk-adjusted returns.

Our key strategic priorities include:

Safety and Operational Reliability
Safety and operational reliability are the foundation of our strategy. We strive to achieve and maintain industry leadership in all facets of safety - process, public, and personal - and ensure the highest standards of reliability and integrity across our system to protect our communities and the environment.

Extend Growth
The table belowcornerstone of our growth lies in the successful execution of our slate of secured projects (currently $24 billion through 2028) on schedule, 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 the near term we will be focused on closing the US gas utilities transactions and successfully integrating each utility. Beyond that, we will continue to seek to identify additional high-quality growth opportunities across all our platforms. We will remain disciplined and deploy capital towards only 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, complementary accretive "tuck-in" acquisitions that improve our competitive positioning, or further strengthening of our balance sheet.

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

Our liquids pipelines infrastructure will remain a vital connection between key supply basins and demand-pull markets such as the refinery hubs in the US Midwest, eastern Canada, and the US Gulf Coast. Our premier liquids system and export infrastructure will also enable crude, clean fuels, and other export opportunities. Building on our early experience, we expect CCS to provide additional new growth opportunities, over the longer-term.

Our natural gas transmission business will seek extension and expansion opportunities driven by new load demand from gas-fired power generation, industrial growth, and coastal LNG plants. Looking forward, producing and blending RNG into our system will enhance asset longevity and enable us to offer differentiated lower-carbon solutions to customers. Over the longer-term, we plan to scale similar opportunities with H2 production, blending, and transportation to further decarbonize our gas offerings and extend asset life.

Our Ontario-based gas distribution and storage business will continue to grow through customer additions, productivity enhancements, modernization investments, and facilities that blend H2 and RNG into the gas supply. Additionally, we will continue to thoughtfully expand our offerings to customers, including additional demand-side management, low-carbon, and distributed energy programs.

Our renewables business is increasingly well positioned to capitalize on the growth of renewables in Europe and North America. We will continue to leverage our expanded internal capabilities and our strong existing partnerships to successfully execute on our large development portfolio and secure the next wave of projects for the future.

In addition, we aim to drive growth through a continuing focus on optimization, modernization, productivity, and efficiency across all our businesses. Examples include: the application of drag-reducing agents and pump station modifications to optimize throughput on our liquids system, the execution of toll settlements and rate case filings to optimize revenue within our liquids pipeline and gas transmission franchises, the expansion of lower-carbon gas offerings to modernize and integrate value chains at our gas utility, and the creation of sustainable cost savings across the organization through innovation, process improvement and system enhancements.

Maintain Financial Strength and Flexibility
Our financing strategies are designed to retain strong, investment-grade credit ratings to ensure we have the financial capacity to meet our capital funding needs and the flexibility to manage capital market disruptions. We expect that the current secured capital program can be readily financed through internally generated cash flow, available balance sheet capacity, and selective asset monetizations. For further discussion on our financing strategies, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources.

Disciplined Capital Allocation
We assess the latest fundamental trends, monitor the business landscape, and proactively conduct business development activities with the goal of identifying an industry-leading capital deployment opportunity set. We screen, analyze, and assess opportunities using a disciplined investment framework with the objective of effectively deploying capital to grow while driving attractive risk-adjusted returns, within our low-risk "utility-like" business model.

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All investment opportunities are evaluated based on their potential to advance our strategy, mitigate risks, support our ESG goals, and create additional financial flexibility. Our primary emphasis in the near term is on low capital intensity opportunities to enhance returns across existing businesses (organic expansions and optimizations), system modernization, and utility rate-based investments. We also remain focused on larger projects where commercial constructs fit our investor value proposition and where we can effectively manage risks during the execution phase. While we will be focused in the near-term on closing our US gas utilities transactions, we are continuing to assess other strong value-enhancing opportunities, including accretive acquisitions that can complement our portfolio.

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

Lead in Energy Transition Over Time
As the global population grows and standards of living continue to improve around the world, we expect energy demand to rise. We, and our society, increasingly recognize the need for secure and reliable energy while concurrently reducing global GHG emissions. Accordingly, energy systems around the world are being reshaped as industry participants, regulators, and consumers seek to balance these factors. As a diversified energy infrastructure company, we believe that we are well positioned to play a key role in the energy transition by lowering the emission-intensity of the conventional fuels we transport and store, supporting the switching from higher emission energy sources to lower-carbon options for our customers, and leading the development and construction of future lower-carbon energy infrastructure that the world needs, along with regulators, policy makers, and other key stakeholders.

We believe that diversification and innovation will play a significant role in the transition to a lower-emission future. To date, we have made large investments in natural gas infrastructure, emissions reduction technologies, and renewable energy assets, helping to decrease our emissions and further expand our platforms to enable energy transition across the globe. Our focus areas in renewable energy remain in offshore wind, utility-scale onshore projects, and integrated clean-energy offerings and solutions for customers. We are also taking a leadership role in other lower-carbon platforms like RNG, blue ammonia, CCS, and H2 where we can leverage our infrastructure, capabilities, and stakeholder relationships to accelerate growth and extend the value of our existing assets. Additionally, all our new investments need to have a clear path to achieve net-zero emissions, in alignment with our ESG goals.

We work closely with our customers and stakeholders to maintain a pulse on the pace of the energy transition and are actively leveraging our ESG leadership and world-class execution capabilities to advance our positioning as a differentiated energy provider. We regularly test our assets under various transition scenarios to ensure the resiliency of our business.

STRATEGIC ENABLERS
To successfully execute on our strategy and build competitive advantage, we focus on having leading-edge capabilities in ESG, talent, technology, operations, development, and growth capabilities.

Environmental, Social and Governance
Sustainability is integral to our ability to deliver energy in a safe and reliable manner. How well we perform as a steward of our environment; as a safe operator of essential energy infrastructure; as a diverse and inclusive employer; and as a responsible corporate citizen is inextricably linked to our ability to achieve our strategic priorities and create long-term value for all our stakeholders.

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In 2023, we published our 22nd annual Sustainability Report outlining our progress against our ESG goals1. In particular, we:

made meaningful progress towards our interim emissions intensity and net-zero GHG emissions goals through modernization and innovation of our system, and continued investment in solar self-power, front of the meter renewables, and execution of additional renewable power PPAs;
enhanced our efforts to ensure that our workforce and the Board better reflect the diversity of our communities, empowering our workforce through employee resource groups and advancing on our diversity, equity, and inclusion commitments; and
continued to drive improvements towards our goal of zero safety incidents and injuries and progressed implementation of robust cyber defense programs.

Since setting our ESG goals in 2020, we have made considerable progress integrating sustainability into our strategy, governance, operations, and decision-making. We have linked ESG performance to incentive compensation and are making meaningful progress towards these goals by executing on our action plans.

We aim to continuously strengthen our ESG approach and are undertaking the following additional actions:

proactively working with organizations that are advancing emissions measurement and reduction guidelines for the midstream sector;
collaborating with key suppliers on emissions reduction plans;
further developing lower-carbon energy partnerships to drive innovation across our businesses, with a focus on renewable power, RNG, H2 and CCS; and
continue to advance our commitment to meaningful reconciliation and to building respectful and collaborative Indigenous partnerships.

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

Talent
Our employees are essential to our success and our focus remains on enhancing the capabilities and skills of our people. We are evolving our talent strategy enhancing our employee experience, and growing our focus on learning and development. We value diversity and diverse thought, and have embedded inclusive practices in our programs, processes, and approach to people management. Furthermore, we strive to maintain industry-competitive compensation, flexibility, and retention programs that provide both short- and long-term performance incentives.

Technology
We recognize the vital role technology plays in helping us achieve our strategic objectives. We are committed to pursuing innovation and technology solutions that further our safety and reliability, maximize revenues, improve efficiencies, and enable transition to new, cleaner energy solutions. We continue to focus on resilience and reliability of our systems from a cybersecurity perspective and work to enhance our capabilities and educate our workforce to protect our critical infrastructure system from increasing threats.


1All 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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Operations & Development
As a major infrastructure developer and operator, Enbridge focuses on excellence in our business, specifically in safety, regulatory, project execution, and efficiency. Safety is foundational at Enbridge and our safety-first mindset reflects our commitment to protecting the public, our workers, the environment, and the health of our pipelines and facilities. We recognize the importance of having strong trusted relationships with our regulators as we plan and execute projects and sustain ongoing operations. We are committed to being proactive on regulatory matters at the federal, regional, and local levels to ensure we develop and maintain a safe and reliable energy system that our customers and the public can count on.

Robust project development, execution, governance, stakeholder relations, and supply chain processes are also key to delivering projects on time, at high quality, and within estimated costs. We continually seek ways to improve our organizational efficiency and effectiveness across all our core functions, including by streamlining structures, simplifying processes, improving accountability, and effectively managing risk to drive top-tier performance.

Growth Capabilities
To achieve our vision and mission, we emphasize specific capabilities that will help us grow and build competitive advantage within our core and potential new businesses. We are increasing our focus on our customers to ensure we are responsive to their needs while also proactively helping them meet their decarbonization objectives. We are continuing to invest in leading corporate development capabilities to ensure we can identify and execute on attractive capital recycling opportunities and acquisitions. Finally, we believe that the future energy system will not only continue to be highly integrated, but also become more complex. This will require an ecosystem of stakeholders, from customers and lenders to original equipment manufacturers and regulators, to develop and manage. We believe it is critical to have strengths in partnership structuring and relationship management to build and maintain the robust energy infrastructure system that the world needs.

BUSINESS SEGMENTS

During 2023, the activities were 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. The Canadian Mainline includes six adjacent pipelines with a combined operating capacity of approximately 3.2 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. Through our predecessors, we have operated, and frequently expanded, the Canadian Mainline since 1949. The Lakehead System is the portion of the Mainline System in the US. It is an interstate common carrier pipeline system regulated by the Federal Energy Regulatory Commission (FERC) and is the primary transporter of crude oil and liquid petroleum from western Canada to the US.

Tolling Framework
The Competitive Toll Settlement (CTS) which governed tolls 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 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.

Enbridge has reached an agreement on a negotiated settlement with shippers for tolls on its Mainline System. The Mainline Tolling Settlement (MTS) covers both the Canadian and US portions of the Mainline and would see the Mainline continuing to operate as a common carrier system available to all shippers on a monthly nomination basis. The MTS is subject to regulatory approval and the term is seven and a half years through the end of 2028, with revised interim tolls effective on July 1, 2023.

The MTS includes:

an IJT, for heavy crude oil movements from Hardisty to Chicago, comprised of a Canadian Mainline Toll of $1.65 per barrel plus a Lakehead System Toll of US$2.57 per barrel, plus the applicable Line 3 Replacement surcharge;
toll escalation for operation, administration, and power costs tied to US consumer price and power indices;
tolls that continue to be distance and commodity adjusted, and utilize a dual currency IJT; and
a financial performance collar providing incentives for Enbridge to optimize throughput and cost, but also providing downside protection in the event of extreme supply or demand disruptions or unforeseen operating cost exposure. This performance collar is intended to ensure the Mainline earns 11% to 14.5% returns, on a deemed 50% equity capitalization, which is similar to the returns earned on average during the previous tolling agreement.

Approximately 70% of Mainline deliveries are tolled under this settlement, while approximately 30% of deliveries are tolled on a full path basis to markets downstream of the Mainline. The other continuing feature is that the Mainline toll flexes up or down US$0.035 per barrel for 50,000 barrel per day changes in throughput.

The expected financial outcome from this settlement is in line with previously reported financial results after taking into consideration the previously recognized provision, inflationary cost adjustments and increased volumes. Enbridge filed an application with the Canada Energy Regulator (CER) for approval of the MTS on December 15, 2023, with unanimous support from its Representative Stakeholder Group. The CER indicated in its process letter that no dissenting comments were received by January 19, 2024 and that it may decide on the application or it may establish further process steps.
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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.

On May 24, 2023, Enbridge filed an Offer of Settlement with the FERC for the Lakehead System (the Lakehead System Settlement). In addition to resolving litigation related to the Index portion of the Lakehead System rate, the Lakehead System Settlement also includes a depreciation truncation date of December 31, 2048 for the rate base applicable to the Index and Facilities Surcharge and agreement on the terms for future recovery through the Facilities Surcharge of costs related to two Line 5 projects: the Wisconsin Relocation Project and the Straits of Mackinac Tunnel. The Lakehead System Settlement was certified by the Settlement Judge on June 23, 2023 and was approved by the FERC Commissioners on November 27, 2023. Lakehead System tolls were revised effective December 1, 2023 to reflect the terms of the Lakehead System Settlement.

REGIONAL OIL SANDS SYSTEM
The Regional Oil Sands System includes seven intra-Alberta long-haul pipelines: the Athabasca Pipeline, Waupisoo Pipeline, Woodland and Woodland Extension Pipelines, Wood Buffalo and 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 the three major oil sands deposits, Athabasca, Cold Lake and Peace River.

The combined capacity of the intra-Alberta long-haul pipelines is approximately 1,120 thousand barrels per day (kbpd) to Edmonton and 1,415 kbpd into Hardisty, with Norlite providing approximately 218 kbpd of diluent capacity into the Fort McMurray region. We have a 50% interest in the Woodland Pipeline and a 70% interest in Norlite. The Regional Oil Sands System is anchored by long-term agreements with multiple oil sands producers that provide cash flow stability and also include provisions for the recovery of some of the operating costs of this system.

On October 5, 2022, we completed a transaction with Athabasca Indigenous Investments Limited Partnership (Aii), a newly created entity representing 23 First Nation and Metis communities, pursuant to which Aii acquired an 11.6% non-operating interest in the seven intra-Alberta long-haul pipelines in the Regional Oil Sands System.

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

Flanagan South is a 950 kilometer (590 mile), 36-inch diameter interstate crude oil pipeline that originates at our terminal at Flanagan, Illinois, a delivery point on the Lakehead System, and terminates in Cushing, Oklahoma. Flanagan South has a capacity of approximately 660 kbpd.

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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.

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.

The Mid-Continent System is comprised of storage terminals at Cushing Terminal, consisting of over 110 individual storage tanks ranging in size from 78 to 570 thousand barrels. Total storage shell capacity of Cushing Terminal is approximately 26 million barrels. A portion of the storage facilities are used for operational purposes, while the remainder are contracted to various crude oil market participants for their term storage requirements. Contract fees include fixed monthly storage fees, throughput fees for receiving and delivering crude to and from connecting pipelines and terminals, and blending fees.

Gray Oak is a 1,368 kilometer (850 mile) crude oil system, with origination points in the Eagle Ford and Permian Basins in West Texas. Gray Oak has delivery points at the US Gulf Coast and Houston refining region. It has an expected average annual capacity of 900 kbpd and transports light crude oil. During December 31, 2023, our effective economic interest in Gray Oak increased to 68.5% from 58.5% as a result of our acquisition of Rattler Midstream’s 10% interest in the pipeline. We assumed operatorship of Gray Oak in April 2023.

In October 2021, we acquired Moda Midstream Operating, LLC, which included the EIEC, located near Corpus Christi, Texas. This terminal is comprised of 15.6 million barrels of storage and 1.5 mmbpd of export capacity. We also acquired a 20% interest in the 670-kbpd Cactus II Pipeline, a 100% interest in the 300-kbpd Viola Pipeline, and a 100% interest in the 350-thousand-barrel Taft Terminal. In November 2022, we acquired an additional 10% ownership interest in Cactus II Pipeline, bringing our total non-operating ownership to 30%.

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

Southern Lights Pipeline is a single stream 180 kbpd 16/18/20-inch diameter pipeline that ships diluent from the Manhattan Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. Both the Canadian portion of Southern Lights Pipeline and the US portion of Southern Lights Pipeline receive tariff revenues under long-term contracts with committed shippers. Southern Lights Pipeline capacity is 90% contracted with the remaining 10% of the capacity assigned for shippers to ship uncommitted volumes. A fully subscribed open season was completed in December 2023, which has ensured contract levels remain at 90% through mid-2030,

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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. The Express Pipeline capacity is typically committed under long-term take-or-pay contracts with shippers. A small portion of the 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 Basin 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 pipelines. 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 regulated 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.

We have an effective 27.6% interest in the Bakken Pipeline System, which connects the Bakken Basin in North Dakota to markets in eastern PADD II and the US Gulf Coast. The Bakken Pipeline System consists of the Dakota Access Pipeline 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 approximately 750 kbpd of crude oil with the potential to be expanded through additional pumping horsepower. The Bakken Pipeline System is anchored by long-term throughput commitments from a number of producers.

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

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

Feeder Pipelines and Other also includes Patoka Storage, the Toledo pipeline system and the Norman Wells (NW) System. Patoka Storage is comprised of four storage tanks with 480 thousand barrels of shell capacity located in Patoka, Illinois. The 180 kbpd Toledo pipeline system connects with the Lakehead System and delivers to Ohio and Michigan. The 45 kbpd NW System transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta and has a cost-of-service rate structure based on established terms with shippers.

COMPETITION
Competition for our liquids pipelines network comes primarily from infrastructure or logistics alternatives (rail, trucking) 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, such as the Trans Mountain Pipeline expansion, 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.

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

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. We expect US demand for Canadian crude oil production will support the use of our infrastructure for the foreseeable future.

Under most base case forecasts, demand 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.

Due to the accelerated developments of offshore production in both Brazil and Guyana and continued growth from Canada and the US, it is expected that Organization of Petroleum Exporting Countries (OPEC) will try to manage prices with continued quota constraints, delaying its growth from its supply. However, production in some OPEC countries, like Iran and Venezuela, has the potential to increase from current levels. In the US, growth will likely be driven by the Permian Basin, 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 likely support expansion of existing projects and some potential new greenfield facilities.

Our Mainline System was effectively fully utilized in 2023 delivering 3.2 mmbpd. Refinery demand in the upper Midwest PADD II market has been strong. 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. Many of the refineries connected to the Mainline System are complex and competitive in the global context.

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

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


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GAS TRANSMISSION AND MIDSTREAM

Gas Transmission and Midstream consists of our investments in natural gas pipelines and gathering and processing facilities in Canada and the US, including US Gas Transmission, Canadian Gas Transmission, US Midstream and other assets.

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

The Texas Eastern interstate natural gas transmission system extends from supply and demand centers in the Gulf Coast region of Texas and Louisiana to supply and demand centers in Ohio, Pennsylvania, New Jersey and New York. Texas Eastern's onshore system has a peak day capacity of 12.0 billion cubic feet per day (bcf/d) of natural gas on approximately 13,765 kilometers (8,553 miles) of pipeline and associated compressor stations. Texas Eastern is also connected to five affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas Transmission business, including the Tres Palacios storage facility that we acquired on April 3, 2023.

The Algonquin interstate natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to M&N US. The system has a peak day capacity of 3.1 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 0.8 bcf/d of natural gas on approximately 552 kilometers (343 miles) of mainline interstate natural gas transmission system, including associated compressor stations, which extends from northeastern Massachusetts to the border of Canada near Baileyville, Maine. M&N Canada has a peak day capacity of 0.5 bcf/d on approximately 885 kilometers (550 miles) of interprovincial natural gas transmission mainline system that extends from Goldboro, Nova Scotia to the US border near Baileyville, Maine. We have a 78% interest in M&N US and M&N Canada.

East Tennessee’s interstate natural gas transmission system has a peak day capacity of 1.9 bcf/d of natural gas, crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems totaling approximately 2,449 kilometers (1,522 miles) of pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East Tennessee has a LNG storage facility in Tennessee and also connects to the Saltville storage facilities in Virginia.

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.

Vector is an approximately 560 kilometer (348 mile) pipeline travelling between Joliet, Illinois in the Chicago area and Ontario. Vector can deliver 1.7 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.

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 1.4 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.


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

NEXUS is an approximately 414 kilometer (257 mile) interstate natural gas transmission system with associated compressor stations. NEXUS transports natural gas from our Texas Eastern system in Ohio to our Vector interstate pipeline in Michigan, with peak day capacity of 1.4 bcf/d. Through its interconnect with Vector, NEXUS provides a 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.

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

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. It also includes the Aitken Creek Gas Storage facility, located in BC, Canada, which we acquired on November 1, 2023.

BC Pipeline provides natural gas transmission services, transporting processed natural gas from facilities located primarily in northeastern BC to markets in BC and the US Pacific Northwest. It has a peak day capacity of 3.6 bcf/d of natural gas on approximately 2,950 kilometers (1,833 miles) of transmission pipeline in BC and Alberta, as well as associated mainline compressor stations. BC Pipeline is regulated by the CER under cost-of-service regulation.

Alliance Pipeline is an approximately 3,000 kilometer (1,864 mile) integrated, high-pressure natural gas transmission pipeline with approximately 860 kilometers (534 miles) of lateral pipelines and related infrastructure. It transports liquids-rich natural gas from northeast BC, northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub downstream of the Aux Sable Liquid Products LP 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.

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On December 13, 2023, we announced that Enbridge has entered into a definitive agreement to sell our 50.0% interest in the Alliance Pipeline and our interest in Aux Sable (including 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and 50% interest in Aux Sable Canada LP) to Pembina Pipeline Corporation for $3.1 billion, including approximately $0.3 billion of non-recourse debt, subject to customary closing adjustments. Closing is expected to occur in the first half of 2024, subject to the receipt of regulatory approvals and satisfaction of customary closing conditions.

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.

US MIDSTREAM
US Midstream includes a 42.7% interest in each of Aux Sable Liquid Products LP and Aux Sable Midstream LLC, and a 50% interest in Aux Sable Canada LP (collectively, Aux Sable). Aux Sable Liquid Products LP owns and operates a NGL extraction and fractionation plant at Channahon, Illinois, outside Chicago, near the terminus of Alliance Pipeline. Aux Sable also owns facilities connected to Alliance Pipeline that 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.

As of August 17, 2022, US Midstream also includes a 13.2% effective economic interest in DCP Midstream, LP (DCP). Prior to August 17, 2022, we had a 28.3% effective economic interest in DCP. DCP is a joint venture, with a diversified portfolio of assets, engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGL; and recovering and selling condensate. DCP owns and operates more than 36 plants and approximately 86,905 kilometers (54,000 miles) of natural gas and NGL pipelines, with operations in nine states across major producing regions.

OTHER
Other consists primarily of our offshore assets. Enbridge Offshore Pipelines is comprised of 12 natural gas gathering and FERC regulated transmission pipelines and five oil pipelines. These pipelines are located in four major corridors in the Gulf of Mexico, extending to deepwater developments, and include almost 2,200 kilometers (1,365 miles) of underwater pipe and onshore facilities with total capacity of approximately 6.6 bcf/d.

In 2023, Enbridge acquired a 10% equity investment in Divert Inc., a RNG infrastructure company, which provides Enbridge with an option to invest up to $1.3 billion (US$1.0 billion) in food waste to RNG projects across the US.

On January 2, 2024, through a wholly-owned US subsidiary, we acquired the first six Morrow Renewables operating landfill gas-to-RNG production facilities located in Texas and Arkansas. The acquired assets align with and advance our low-carbon strategy.

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.

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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.

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

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

Natural gas production in the Appalachian and Permian Basins has grown dramatically in the past decade. Today, these regions produce more than 53 bcf/d of natural gas on a combined basis. Improved technology and increased shale gas drilling have increased the supply of low-cost natural gas. As well, there has been, and continues to be, a corresponding increase in demand for our natural gas infrastructure in North America. Through a series of expansions and reversals on our core systems, combined with the execution of greenfield projects and strategic acquisitions, we have been able to meet the needs of both producers and consumers. Our US Gas Transmission systems were initially designed to transport natural gas from the Gulf Coast to the supply-constrained northeast markets. Our asset base now has the capability to transport diverse bi-directional supply to the northeast, southeast, Midwest, Gulf Coast and LNG markets on a fully subscribed and highly utilized basis.

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

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

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

Gulf Coast demand growth is being driven by an increase in the volume of LNG exports, an ongoing wave of gas-intensive petrochemical facilities and additional pipeline exports to Mexico. Demand in these markets in the region is anticipated to grow by approximately 20 bcf/d through 2040. The Gulf Coast market has been the beneficiary of low-cost capacity on our assets as the relationship between supply and market centers has shifted. Such cost-effective capacity is difficult to access or replicate, offering existing shippers and transporters stability of capacity and utilization. Tide-water market access and proximity to Mexico continue to make this region a platform of global trade as pipeline and LNG exports continue their growth trajectory. In 2023, the US exported over 11.9 bcf/d of natural gas to LNG markets, primarily from the Gulf Coast region.

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Western Canada is also 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 is our own systems in the region, which are highly utilized. The continental supply profile has shifted to natural gas shale plays such as the Montney and Duvernay within western Canada. These plays will fulfill an integral role as Canada enters the global market as an LNG exporter. Western Canada's production is forecasted to increase from 18 bcf/d in 2023 to 22 bcf/d by 2040. This growth will support an additional 4 bcf/d of LNG exports. These supply shifts have shaped our growth strategies and affect the nature of the projects anticipated in the capital expenditures discussed below in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

Global energy demand is expected to increase approximately 21% by 2050, according to the recently released International Energy Agency’s Stated Policy Scenario, driven primarily by economic growth in non-OECD countries. According to the Stated Policy Scenario, natural gas will play an important role in meeting this energy demand, and gas consumption is anticipated to grow by approximately 11% during this period as one of the world’s most significant energy sources. North American exports are expected to play a significant part in meeting global demand, underscoring the ability of our assets to remain highly utilized by shippers, and highlighting the need for incremental transportation solutions across North America, as well as for the further build-out of export facilities to meet international demand.

The long-term effects on global gas markets of the ongoing conflict in Ukraine remain uncertain. In 2022, Europe saw a sharp rise in natural gas prices due to a decrease in supply from Russia. Global LNG markets responded, and LNG cargoes were redirected from the Asian market to Europe which allowed Europe to meet peak demand during what turned out to be a mild winter. Natural gas storage volumes have been strong entering the 2023-2024 winter season in Europe, and mild winter temperatures have thus far helped to moderate prices. The outlook for gas prices remains somewhat volatile but is generally anticipated to see a gradual normalization.

Europe continues to seek lower-carbon gas supplies and has accelerated plans to develop hydrogen as an alternative to natural gas. The global hydrogen market is still relatively immature, but with incentives being put in place such as those in the US Inflation Reduction Act, hydrogen production at large scale is becoming increasingly commercialized, which has led to a growing export market. Given its proximity to low-cost natural gas supplies and suitable geologic storage for carbon dioxide, the US Gulf Coast is well positioned to be a leading export hub to supply blue hydrogen to international markets. Given these rapidly changing global fundamentals, and coupled with growing appetite for lower-carbon hydrogen, we believe we are well positioned to provide value-added solutions to shippers and meet both regional and international demand.

Opposition to natural gas development, including new pipeline projects, has been increasing in recent years. This may challenge continued growth of the North American gas market and the ability to efficiently connect supply and demand. We are responding to the need for regional infrastructure with additional investments in Canadian and US gas transportation facilities. Progress on the development and construction of our commercially secured growth projects is discussed in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

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RNG is seen as a sustainable and more environmentally friendly alternative to traditional natural gas, derived from organic waste sources such as agricultural residues, food waste, and other organic waste material. The production process most commonly involves the anaerobic digestion of these organic materials, resulting in the generation of biogas composed primarily of methane. Unlike conventional natural gas, RNG is considered carbon-neutral or even carbon-negative, as the carbon dioxide that is ultimately released during combustion is offset by the carbon captured during the organic matter's growth. This closed-loop cycle can contribute to mitigating GHG emissions and help to address climate change concerns. RNG can be seamlessly integrated into existing natural gas infrastructure, offering a versatile energy source for heating, transportation, and electricity generation. As societies increasingly prioritize sustainability, RNG has the potential to play an important role in the transition towards a cleaner and more resilient energy future. We believe that RNG is poised for growth as the global focus on sustainable energy solutions intensifies. Global RNG consumption is expected to increase with a 11% compound annual growth rate until 2050, according to the recently released International Energy Agency’s Stated Policy Scenario.

GAS DISTRIBUTION AND STORAGE

Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge Gas Inc. (Enbridge Gas), which serves residential, commercial and industrial customers throughout Ontario. This business segment also includes natural gas distribution activities in Québec.

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ENBRIDGE GAS
Enbridge Gas is a rate-regulated natural gas distribution utility with storage and transmission services. Enbridge Gas' distribution system, supported by storage and compression assets, carries natural gas from the point of local supply to customers and serves residential, commercial and industrial customers across Ontario.

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

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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 151,000 kilometers (93,827 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 3,800 kilometers (2,361 miles) of high pressure pipeline and five mainline compressor stations and has an effective peak daily demand capacity of 7.6 bcf/d. Enbridge Gas’ transmission system also links an extensive network of underground storage pools at the Tecumseh Gas Storage facility and Dawn Hub (collectively, Dawn) to major Canadian and US markets, and forms an important link in moving natural gas from western Canada and US supply basins to central Canadian and northeastern US markets.

As the supply of natural gas in areas close to Ontario has continued to grow, there has been increased demand to access these diverse supplies at Dawn and transport them along the Dawn-Parkway pipeline system to markets in Ontario, eastern Canada and the northeastern US. Enbridge Gas delivered 2,218 bcf of gas through its distribution and transmission system in 2023. 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 17 years and the longest remaining contract term being 17 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 284 bcf in 33 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 2023, Dawn provided services such as storage, balancing, gas loans, transport, exchange and peaking services to approximately 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 three years and the longest remaining contract term being 13 years.

GAZIFÈRE
We wholly own Gazifère Inc. (Gazifère), a natural gas distribution company that serves approximately 45,000 customers in western Québec. Gazifère is regulated by the Québec Régie de l’énergie.

US GAS UTILITIES
On September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina for an aggregate purchase price of $19.1 billion (US$14.0 billion). If completed, the Acquisitions will create North America's largest natural gas utility platform delivering over 9 bcf/d to approximately 7 million customers across multiple regulatory jurisdictions. The Acquisitions are expected to close in 2024, subject to the satisfaction of customary closing conditions including the receipt of certain regulatory approvals, which are not cross-conditional.

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

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

SUPPLY AND DEMAND
We anticipate that demand for natural gas in North America will stabilize over the long term with potential growth in peak day demands; however, there are risks to the natural gas market that may challenge its growth prospects. The recent decision by the OEB on Enbridge Gas' application to establish 2024 base rates, net-zero carbon policies, evolving customer preferences for lower-carbon fuels and more efficient technologies, combined with increasing opposition to natural gas development in North America, may reduce the markets’ ability to efficiently deploy capital to connect supply and demand. We monitor these factors closely to be able to develop our business strategy to align with shifts in customer preferences and public policy requirements.

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The recent decision by the OEB on Enbridge Gas' application to establish 2024 base rates includes changes to the revenue horizon over which costs can be recovered for small volume customer connections. The implications of the recent OEB decision are being assessed. Refer to Regulation - Government Regulations - Gas Distribution and Storage for further discussion.

Enbridge Gas continues to focus on promoting conservation and energy efficiency by undertaking activities focused on reducing natural gas consumption through various demand side management programs offered across all markets and sourcing supply with a smaller carbon footprint. In addition to our existing and proposed RNG programs, we are also continuing our efforts to source other lower-carbon supplies, such as responsibly sourced natural gas, and H2.

Over the past decade, growth in the North American gas supply landscape, driven mainly by the development of unconventional gas resources in the Montney, Permian, Marcellus and Utica supply basins, has resulted in lower annual commodity prices and narrower seasonal price spreads. However, over the past two years, geopolitical unrest has increased and led to elevated concerns with energy security in regions such as Europe and Asia. In response, one of the key supply sources supporting global energy security has been US LNG, which has introduced additional competition for North American supply. These market dynamics have resulted in higher and more volatile natural gas prices across many US and Canadian natural gas trading points. Unregulated storage values are primarily determined by the difference in value between winter and summer natural gas prices. As a result of the recent volatility exhibited in natural gas prices, storage values have risen.

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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, Ontario and Québec, and in the states of Colorado, Texas, Indiana, Ohio and West Virginia. In Europe, we hold equity interests in operating offshore wind facilities in the coastal waters of the United Kingdom, France, and Germany, as well as interests in several offshore wind projects under construction and active development in France and the United Kingdom.

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Combined Renewable Power Generation investments represent approximately 2,371 MW of net generation capacity, which primarily consists of approximately:

1,399 MW generated by North American wind facilities;
526 MW generated by European offshore wind facilities;
186 MW expected to be generated by the Fécamp and Calvados Offshore Wind Projects in France, both of which are currently under construction;
6 MW expected to be generated by the Provence Grand Large Floating Offshore Wind Project in France, which is under construction; and
198 MW generated by North American solar facilities in operation, with an additional 30 MW in projects in pre-construction and under construction.

The vast majority of the power produced from these facilities is sold under long-term PPAs.

Renewable Power Generation also includes our 24.1% interest in the East-West Tie, a 450-MW transmission line in northwestern Ontario, which entered operations in March 2022.

JOINT VENTURES / EQUITY INVESTMENTS
Most of our investments in Canadian wind and solar assets and two of our US renewable assets are held within a joint venture in which we maintain a 51% interest and which we manage and operate. One of our US solar projects is held within a separate joint venture in which we hold a 50% stake.

We also own interests in European offshore wind facilities through the following table presentsjoint ventures:

a 24.9% interest in Rampion Offshore Wind, located in the reconciliationUnited Kingdom;
a 49.9% interest in Hohe See and Albatros Offshore Wind, located in Germany;
a 25.5% interest in the Saint-Nazaire Offshore Wind Project, located in France;
a 25% interest in the Provence Grande Large Floating Offshore Wind Project, under construction in France;
a 17.9% interest in the Fécamp Offshore Wind Project, under construction in France; and
a 21.7% interest in the Calvados Offshore Wind Project, under construction in France.

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

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

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

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

On the supply side in North America, legislation is accelerating the retirement of aging coal-fired generation, while generation from conventional nuclear power is also forecast to decline. As a result, North America requires significant new generation capacity from preferred technologies. Gas-fired and renewable energy facilities, including solar and wind (which make up the bulk of our renewable power assets), are generally the preferred sources to replace coal-fired generation due to their lower-carbon intensities. Governments are also proposing tax incentives to support low-emission and renewable energy generation resource development. As renewable energy takes an increasing share of certain states’ and provinces’ electricity grids, governments are also proposing tax incentives for natural gas and battery development to help firm the variable generation on the grid.

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 extend the project-life of, our existing facilities.

In Europe, the renewable energy outlook is robust. Demand for electricity is expected to gradually increase over the next two decades, driven by electrification of transportation and buildings, and the desire to reduce reliance on gas sourced from Russia. Energy efficiency gains are expected to temper, but not eliminate, demand growth. Renewable power is expected to play a significant role in Europe’s ability to meet its aggressive lower-carbon and renewable energy targets.

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

ENERGY SERVICES

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

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

Effective January 1, 2024, to better align how the chief operating decision-maker reviews operating performance and resource allocation across operating segments, we transferred our Canadian and US crude oil businesses from the Energy Services segment to the Liquids Pipelines segment. The Energy Services segment will cease to exist and the remainder of the business will be reported in the Eliminations and Other segment.
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COMPETITION
Energy Services’ earnings are primarily generated from arbitrage opportunities which, by their nature, can be replicated by competitors. An increase in market participants entering into similar arbitrage strategies could have an impact on our earnings. Efforts to mitigate competition risk include diversification of the marketing business by transacting at the majority of major hubs in North America and establishing long-term relationships with clients and pipelines.

ELIMINATIONS AND OTHER

Eliminations and Other includes operating and administrative costs that are not allocated to business segments, the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. The principal activity of our captive insurance subsidiaries is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. Eliminations and Other also includes new business development activities and corporate investments.

REGULATION

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

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

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

Our ability to establish transportation and storage rates on our US interstate natural gas facilities is subject to regulation by the FERC, whose rulings and policies could have an adverse impact on the ability to recover the full cost of operating these pipeline and storage assets, including a reasonable rate of return. Regulatory or administrative actions by the 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 pipelines are subject to safety regulations administered by the CER or provincial regulators. Applicable legislation and regulations require us to comply with a significant set of requirements for the design, construction, maintenance and operation of our pipelines. Among other obligations, this regulatory framework imposes requirements to monitor and maintain the integrity of our pipelines.

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As in the US, laws and regulations addressing enhanced pipeline safety in Canada have been enacted over the past few years. The changes demonstrate an increased focus on the implementation of management systems to address key areas, such as emergency management, integrity management, safety, security and environmental protection. The CER has authority to impose administrative monetary penalties for non-compliance with the regulatory regime it administers, as well as to impose financial requirements for future abandonment and major pipeline releases.

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

Our pipelines also face economic regulatory risk. Broadly defined, economic regulatory risk is defined as cash flow provided by operating activities beforethe risk that governments or regulatory agencies reject or revise proposed commercial arrangements, applications or policies, upon which future and current operations are dependent. Our pipelines are subject to the actions of various regulators, including the CER and the FERC, with respect to tariffs and tolls. The rejection or revision of applications for approval of new tariff structures or proposed commercial arrangements and changes in operatinginterpretation of existing regulations by courts or regulators could have an adverse effect on our revenues and earnings.

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

Enbridge Gas' distribution rates, were set under a five-year incentive regulation (IR) framework using a price cap mechanism, which ended on December 31, 2023. The price cap mechanism established new rates each year through an annual base rate escalation at inflation less a 0.3% productivity factor, in addition to annual updates for certain costs to be passed through to customers, and where applicable, provided for the recovery of material discrete incremental capital investments beyond those that could be funded through base rates. The IR framework included the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that required Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved return on equity (ROE).

In October 2022, Enbridge Gas filed its application with the OEB to establish a 2024 through 2028 IR rate setting framework. The application initially sought approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term. A third phase (Phase 3) has been established with the OEB as part of the Phase 1 Partial Settlement Proposal (Settlement Proposal).

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On August 17, 2023, the OEB approved the Settlement Proposal to support the determination of just and reasonable rates effective January 1, 2024. Items resolved in whole or in part include:

additions to rate base up to and including 2022;
interest rates on debt and return on equity;
deferral and variance accounts;
Indigenous engagement; and
rate implementation approach for 2024.

On December 21, 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). The decision addressed three main areas: energy transition, Enbridge Gas Distribution Inc. and Union Gas Limited amalgamation and harmonization issues, and other issues. The Phase 1 Decision included the following key findings or orders:

energy transition risk requires Enbridge Gas to carry out a risk assessment to consider further risk mitigation measures in three areas: system access and expansion capital spending, system renewal capital spending and depreciation policy;
our 2024 capital plan must be reduced by $250 million with a focus on monitoring, repair and life extension of our assets and liabilities (including changesa further $50 million of capitalized indirect overhead costs must be expensed, escalating to $250 million per year during the IR term with an offsetting adjustment to revenues in environmental liabilities) less distributionseach year;
all new small volume customers wishing to noncontrolling interestsconnect to natural gas pay their full connection costs as an upfront charge rather than through rates over time effective January 1, 2025;
approval of a harmonized depreciation methodology that reduced the level of depreciation sought and redeemable noncontrolling interests, preference share dividendsadjusted asset lives including extensions of service life for certain asset classes;
an increase in equity thickness from 36% to 38% effective for 2024; and maintenance capital expenditures,
January 1, 2024 will be the effective date for 2024 rates.

The issues addressed in the Settlement Proposal and further adjustedthe Phase 1 Decision resulted in the following items not approved for unusual,
non-recurring
or
non-operating
factors. Management also uses DCF to assessfuture recovery, and the performance of the company and to set its dividend payout target. DCFsubsequent impairments recognized for the year ended December 31, 20202023:

a portion of undepreciated capital projects removed from 2024 rate base of $41 million;
undepreciated integration capital costs removed from 2024 rate base of $84 million; and
pre-2017 Union Gas Limited related pension balances of $156 million.

Enbridge Gas filed a Notice of Appeal in the Ontario Divisional Court on January 22, 2024 regarding four aspects of the Phase 1 Decision: small volume customer revenue horizon, the 2024 capital plan reduction, the extension of service life for certain asset classes and equity thickness. On January 29, 2024 Enbridge Gas also filed a Notice of Motion with the OEB requesting the OEB to review and vary five aspects of the Phase 1 Decision: small volume customer revenue horizon, the 2024 capital plan reduction, integration capital, depreciation and equity thickness. The outcome of these proceedings is uncertain.

The Phase 1 Decision results in interim rates, pending phases 2 and 3 of the proceeding, resolution of the Notice of Appeal, Notice of Motion and any possible legislative steps that could be undertaken by the Government of Ontario further to the Ontario Minister of Energy's December 22, 2023 news release. Phase 2 will establish and determine the incentive rate mechanism for the remainder of the rebasing term, and gas cost and unregulated storage cost allocation. Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones.

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

On July 19, 2023, Enbridge Gas filed an application seeking approval for the cost consequences associated with two IRP pilot projects. The projects are designed to implement demand-side IRP alternatives, including enhanced targeted energy efficiency and residential demand response programs, in combination with supply-side IRP alternatives, in select communities in order to mitigate identified system constraints and associated facility projects. The pilot projects are intended to provide learnings on the performance of the selected IRP alternatives, including the potential for scalability, that can be leveraged in future IRP alternative plan design. An OEB decision is expected during 2024.

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

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

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

In Canada, the Federal Government does not generally regulate the electricity sector, though it has imposed a federal carbon price on other sectors via its output-based pricing system (OBPS) and has proposed a Clean Electricity Regulation (CE Regulation) that would require Canada’s electricity grid to reach net-zero by 2035. The CE Regulation is expected to come into effect in 2024.

Policy changes may also provide new opportunities for existing assets and new developments. The US passed the Inflation Reduction Act in late 2022, which established long-term production and investment tax credits for renewable power generation, battery storage projects and for related manufacturing supply chains. Similarly, Canada has prepared legislation that would establish competitive tax credits for renewable power generation and battery storage projects, which it anticipates passing in early 2024. Changes to these tax programs could impact development plans.

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Renewable Power Generation is also subject to provincial and state regulations governing the energy resource mix on the grid, emissions levels of the electricity grid, and market regulations related to emergency operations, extreme weather preparedness, and market participation, among others. These regulations may change from time to time, which could impact Enbridge’s operations and increase the costs of participating in regional electricity markets. In 2023, Texas introduced firming requirements that would require new wind and solar projects to be paired with batteries or other firm power supply and/or introduced caps on the percentage of the grid’s power that can be provided by variable generation. Other state and provincial governments are considering similar legislation.

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, the European Green Deal, and ongoing work on financing mechanisms and transmission directives and programs. The EU is also responsible for establishing environmental protection rules and permitting standards. During 2022, member states of the EU introduced extraordinary and temporary measures to address high energy prices including caps and demand reduction goals. As the minimum PPA prices in Germany and France are still honored, there are no negative implications to our PPA prices. The federal policies and regulations in place are subject to change from time to time, which could impact our operations and related expenditures; however, the EU’s general direction is to facilitate increased renewable power integration to its grid.

The United Kingdom (UK) government is responsible for establishing renewable energy and carbon pricing policies for the entire UK, as well as long-term electricity sector planning and procurement mechanisms and structure for auctions that are administered at the national level, e.g., England, Scotland, within the UK. Each country within the UK is also responsible for establishing its own environmental and permitting regulations. This process is still ongoing following Brexit and in some cases continues to result in more volatile merchant power prices; however, expanded interconnectors to Europe and policies aimed at increasing domestic renewable capacity are in progress. Governments have introduced temporary price controls, effective January 1, 2023, to address the significant increase in energy prices. The impact of merchant exposure on our Renewable Power Generation asset in the UK is limited by fixed revenue payments backed by the UK government.

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

In the US, commodity marketing is regulated by the Commodity Futures Trading Commission, the FERC, the SEC, the Federal Trade Commission, the various commodity exchanges, the US Department of Justice and state regulators. The provincial and territorial securities regulators similarly regulate commodity marketing within Canada and are members of the Canadian Securities Administrators. These various regulators enforce, among other things, the prohibition of market manipulation, fraud and disruptive trading.

The regulation of wholesale sales of electric energy is also regulated by the FERC, which authorizes Energy Services to sell electricity at market-based rates.

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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 import and export rules and permits could result in an inability to perform day to day operations, and can 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 DOT, Transport Canada and provincial regulation. Each jurisdiction requires compliance with security, safety, emergency management, and environmental laws and regulations related to ground transportation of commodities. Risks associated with transportation of crude or natural gas liquids include unplanned releases. In the event of a release, remediation of the affected area would be required. Energy Services engages third parties, such as Emergency Response Assistance Canada, the Chemical Transportation Emergency Center and the Canadian Transport Emergency Center to assist in such remediation.

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

In particular, in the US, compliance with major Clean Air Act regulatory programs may cause us to incur significant capital expenditures to obtain permits, evaluate off-site impacts of our operations, install pollution control equipment, and otherwise assure compliance. Some equipment in states in which we operate are affected by the Good Neighbor Rule establishing new emission limits for nitrogen oxides. In addition, there are evolving regulations on environmental justice that could impact Enbridge facilities. The precise nature of these compliance obligations at each of our facilities has not been finally determined and may depend in part on future regulatory changes. In addition, compliance with new and emerging environmental regulatory programs may significantly increase our operating costs compared to historical levels.

In the US, climate change action is evolving at federal, state and regional levels. Pursuant to federal regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities. On December 2, 2023 the Environmental Protection Agency (EPA) released a final rule to minimize methane emissions for new and existing crude oil and natural gas facilities, coupled later with a fee for excess emissions. The current US presidential administration has been convertedimplementing policies designed to DCFcombat climate change and reduce GHG emissions. 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. Based on proposed changes to measure, report and mitigate GHG emissions the expectation is that there will be a significant increase in costs to maintain and report compliance for businesses in our industry.

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Canada has adopted a pan-Canadian approach to pricing carbon emissions to incent GHG emission reductions across all sectors of the economy. This approach was adopted in 2016 and entails both a consumer price on carbon, and an intensity-based system for industry which addresses competitiveness and carbon leakage. Provinces and territories may implement their own system of carbon pricing provided it meets the federal benchmark (and if they fail to do so the federal system will be imposed on them). In March 2022, Canada published its 2030 Emissions Reduction Plan (ERP) which builds on the Pan-Canadian Framework, and Net-Zero Emissions Accountability Act, and details the roadmap for Canada to meet its domestic climate target of a 40-45% reduction in GHG emissions by 2030 and attaining net-zero emissions by 2050. The ERP details the complementary policies and programs that Canada will enact to enable it to meet its domestic climate goal. Effective January 1, 2023, the federal carbon price was increased from $50 to $65 per tonne of carbon dioxide equivalent (tCO2e). This will increase by $15 per tonne each year and rise to $170 per tCO2e in 2030.

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

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

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

The gas distribution system and our other operations must maintain environmental approvals and permits from regulators to operate. As a result, these assets and facilities are subject to periodic inspections and/or audits. Reports are submitted to our regulators as required to demonstrate we are in good standing with our environmental requirements. Failure to maintain regulatory compliance could result in operational interruptions, fines, and/or orders for additional pollution control technology or environmental mitigation.

As environmental regulations continue to evolve and become more stringent, the cost to maintain compliance and the time required to obtain approvals continues to increase. A recent example includes the implementation of the new excess soil management requirements (Ontario Regulation 406/19) which has resulted in an increase in soil management costs and effort.

As in previous years, in 2023 we reported operational GHG emissions, including emissions from stationary combustion, flaring, venting and fugitive sources to Environment and Climate Change Canada, the Ontario Ministry of Environment, Conservation and Parks, and a number of voluntary reporting programs. In accordance with the provincial GHG regulations, stationary combustion and flaring emissions related to storage and transmission operations were verified in detail by a third-party accredited verifier with no material discrepancies found.

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

In October 2018, the federal government confirmed that Ontario is subject to the federal government’s carbon pricing program, otherwise known as the Federal Carbon Pricing Backstop Program. This program consists of two components: a carbon charge levied on fossil fuels, including natural gas, and an OBPS. This program applies in whole or in part to any province or territory that requested it or that did not have an equivalent carbon pricing system in place by January 1, 2019.

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, rising to 12.39 cents/m3 in 2023. As confirmed by the federal government in July 2021, the federal carbon price will increase by $15 per tonne each year beginning in 2023, rising to $170 per tCO2e in 2030. This will equate to a federal carbon charge of 32.40 cents/m3 in 2030.

In September 2020, Ontario and the federal government announced that the federal government has accepted that Ontario’s Emission Performance Standards (EPS) will replace the federal OBPS for industrial facilities. In March 2021, the federal government announced that the federal OBPS would stand down in Ontario at the end of 2021 and Ontario would transition to the EPS effective January 1, 2022. In September 2021, the Greenhouse Gas Pollution Pricing Act was amended to remove Ontario as a covered province, enabling the EPS to take effect on January 1, 2022. Effective January 1, 2022, Enbridge Gas transitioned out of the federal OBPS to the provincial EPS. Enbridge Gas is registered with the Ontario Ministry of the Environment, Conservation and Parks as a covered facility under the EPS and has an annual compliance obligation for its facility-related stationary combustion and flaring emissions associated with its transmission and storage operations. Enbridge Gas must remit payment annually on the portion of emissions that exceed its total annual emissions limit. Payment is due the year following a compliance period and as such, Enbridge Gas remitted payment for its 2022 EPS compliance obligation in November 2023. Enbridge Gas will remit payment for its 2023 EPS compliance obligation in 2024.

Enbridge Gas applies to the OEB annually through a Federal Carbon Pricing Program application for approval of just and reasonable rates effective April 1 each year for the Enbridge Gas Distribution Inc. and Union Gas Limited rate zones, to recover the costs associated with the Federal Carbon Charge and EPS Regulation as a pass-through to customers.

Renewable Power Generation
In summer 2023, the Federal Government of Canada introduced its draft CE Regulation that would cap emissions on electricity generation resources on Canada’s grid. The CE Regulation would cap emissions from electricity generation sources at, or near zero tCO2e per megawatt hour. Details of the CE Regulation and related compliance are under negotiation with the provinces at this time, at least one of which has taken steps to formally resist the adoption of the CE Regulation. The Federal Government anticipates adopting the CE Regulation in 2024, which would begin to apply to projects in 2035, as drafted.

Similarly, the US EPA introduced emissions caps for utilities that would apply to certain coal and natural gas generation facilities by 2035. The caps would require applicable facilities to either capture a portion of carbon emissions and/or to co-fire using hydrogen.

Enbridge’s Renewable Power Generation resources are substantially non-emitting.

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HUMAN CAPITAL RESOURCES

WORKFORCE SIZE AND COMPOSITION
As at December 31, 2023, we had approximately 11,500 regular employees, including approximately 1,500 unionized employees across our North American operations. This total rises to just over 13,400 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, continues to result in strong performance compared against industry benchmarks and we are actively engaged in continuous improvement exercises as we pursue our goal of zero incidents.

DIVERSITY, EQUITY AND INCLUSION
In 2020, we announced Enbridge’s ESG goals – including goals to increase representation of women, underrepresented ethnic and racial groups (including Indigenous peoples), people with disabilities and veterans – to ensure our workforce is reflective of the communities where we operate. In executing on our ESG strategy, we continue to track progress towards these representation goals in 2023. Consistent with our culture, we remain committed to open, two-way dialogue related to our goals, enhancing transparency and accountability for all stakeholders.

Diversity Representation Goals
esggoals_2022.jpg

PRODUCTIVITY AND DEVELOPMENT
We continually invest in our people’s personal and professional development and productivity because we recognize their success is our success. Employees are provided access to leading productivity tools and technology, and can opt in to a range of development and growth opportunities through a variety of channels, which encourages employees to build new skills needed for our core and emerging lines of business and the broader energy transition.

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EXECUTIVE OFFICERS

The following table sets forth information regarding our executive officers as at February 9, 2024:

NameAgePosition
Gregory L. Ebel59President & Chief Executive Officer
Patrick R. Murray49Executive Vice President & Chief Financial Officer
Colin K. Gruending54Executive Vice President & President, Liquids Pipelines
Cynthia L. Hansen59Executive Vice President & President, Gas Transmission and Midstream
Michele E. Harradence55Executive Vice President & President, Gas Distribution & Storage
Matthew A. Akman56Executive Vice President, Corporate Strategy & President, Power
Reginald D. Hedgebeth56Executive Vice President, External Affairs and Chief Legal Officer
Maximilian G. Chan45Senior Vice President & Corporate Development Officer
Laura J. Sayavedra56Senior Vice President, Safety, Projects & Chief Administrative Officer

Gregory L. Ebel was appointed President and Chief Executive Officer (CEO) on January 1, 2023. Mr. Ebel is also a member of the Enbridge Board of Directors. Mr. Ebel served as Chair of the Enbridge Board of Directors following the merger of Enbridge and Spectra Energy Corp (Spectra Energy) in 2017 until January 1, 2023. Prior to that time, he served as Chairman, President and CEO of Spectra Energy from 2009 until February 27, 2017. Previously, Mr. Ebel also served as Spectra Energy’s Group Executive and Chief Financial Officer beginning in 2007, President of Union Gas Limited from 2005 until 2007, and Vice President, Investor & Shareholder Relations of Duke Energy Corporation from 2002 until 2005.

Patrick R. Murray was appointed Executive Vice President & Chief Financial Officer (CFO) on July 1, 2023. Mr. Murray has oversight for all of Enbridge’s financial affairs including investor relations, financial reporting, financial planning, treasury, tax, insurance, risk and audit management functions. He also leads Enbridge’s technology and information services teams. Prior to assuming his current role, Mr. Murray was Senior Vice President & Chief Accounting Officer of Enbridge from June 2020 to June 2023, Vice President, Financial Planning & Analysis and Controller from June 2019 to May 2020,and Vice President, Financial Planning & Analysis from February 2017 to June 2019. Mr. Murray joined Enbridge over 25 years ago and has held a variety of roles within internal audit, corporate accounting, investor relations, treasury, and corporate development during that time.

Colin K. Gruending was appointed Executive Vice President and President, Liquids Pipelines on October 1, 2021. Mr. Gruending is responsible for the overall leadership and operations of Enbridge’s Liquids Pipelines business. Previously, he served as our Executive Vice President and Chief Financial Officer from June 2019 to October 2021; Senior Vice President, Corporate Development and Investment Review from May 2018 to June 2019; and Vice President, Corporate Development and Investment Review from February 2017 to May 2018.

Cynthia L. Hansen was appointed Executive Vice President and President, Gas Transmission and Midstream on March 1, 2022. Ms. Hansen is responsible for the overall leadership and operations of Enbridge’s natural gas pipeline and midstream business across North America. Previously, she served as our Executive Vice President, Gas Distribution and Storage from June 2019 to March 2022 and as Executive Vice President, Utilities and Power Operations from February 2017 to June 2019. Ms. Hansen is also the Executive Sponsor for Asset and Work Management Transformation across Enbridge, working with other business unit leaders.

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Michele E. Harradence was appointed Executive Vice President & President, Gas Distribution & Storage on March 5, 2023. She is responsible for the overall leadership and operations of Ontario-based Enbridge Gas, as well as Gazifère, which serves the Gatineau region of Québec. Prior to assuming her current role, Ms. Harradence was Senior Vice President & President, Gas Distribution and Storage from March 2022 to March 2023. Prior thereto, she was Senior Vice President and Chief Operations Officer of Enbridge’s Gas Transmission and Midstream business unit from June 2019 to March 2022 and Senior Vice President Operations, Gas Transmission and Midstream from February 2017 to June 2019.

Matthew A. Akman was appointed Executive Vice President, Corporate Strategy & President, Power on March 5, 2023. Mr. Akman is responsible for the overall leadership and operations of Enbridge’s power business and also leads our new energy technologies and corporate strategy efforts. Prior to assuming his current role, Mr. Akman was Senior Vice President, Corporate Strategy & President, Power from January 2023 to March 2023. Prior thereto, he was Senior Vice President, Strategy, Power & New Energy Technologies from October 2021 to December 2022, and Senior Vice President, Strategy & Power from June 2019 to October 2021. Mr. Akman joined Enbridge in early 2016 as our head of Corporate Strategy and also previously held responsibilities for Corporate Development and Investor Relations.

Reginald D. Hedgebeth was appointed Executive Vice President, External Affairs and Chief Legal Officer on January 1, 2024. Mr. Hedgebeth leads our legal, public affairs, communications & sustainability, corporate security and aviation teams across the organization. Prior to joining Enbridge, Mr. Hedgebeth served as Chief Legal Officer of Capital Group from January 2021 to June 2023, Executive Vice President, General Counsel and Chief Administrative Officer of Marathon Oil Corporation from April 2017 to December 2020 and, prior to its merger with Enbridge in 2017, General Counsel, Corporate Secretary and Chief Ethics and Compliance Officer for Spectra Energy.

Maximilian G. Chan was appointed Senior Vice President & Corporate Development Officer on March 1, 2022. He was later appointed to the Executive Leadership team on May 8, 2023. Mr. Chan is responsible for the oversight of mergers and acquisitions, capital allocation, investment review, integration and corporate growth objectives. Prior to assuming his current role, Mr. Chan was Vice President, Treasury and Head of Enterprise Risk for Enbridge from February 2020 to March 2022,and Vice President, Treasury from July 2018 to February 2020.

Laura J. Sayavedra was appointed Senior Vice President, Safety, Projects & Chief Administrative Officer on January 1, 2024. Ms. Sayavedra is responsible for the oversight of our safety, capital project execution, human resources, real estate and supply chain management functions. Prior to assuming her current role, Ms. Sayavedra was Senior Vice President, Safety & Reliability, Projects and Unify from March 2022 to December 2023. Prior to that, she led Finance Transformation at Enbridge, and prior to its merger with Enbridge in 2017, was also Vice President & Treasurer for Spectra Energy, and CFO of Spectra Energy Partners LP. She has held various finance, strategy, and business development executive leadership roles.

ADDITIONAL INFORMATION

Additional information about us is available on our website at www.enbridge.com, on SEDAR+ at www.sedarplus.ca 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).

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ENBRIDGE GAS INC.
Additional information about Enbridge Gas can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2023, 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.sedarplus.ca. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

ENBRIDGE PIPELINES INC.
Additional information about Enbridge Pipelines Inc. (EPI) can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2023, 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.sedarplus.ca. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

WESTCOAST ENERGY INC.
Additional information about Westcoast can be found in its financial statements and MD&A for the year ended December 31, 2023, 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.sedarplus.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

ITEM 1A. RISK FACTORS

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

RISKS RELATED TO CLIMATE CHANGE

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

PHYSICAL RISKS
Climate-related physical risks, resulting from changing and more extreme weather, can damage our assets and affect the safety and reliability of our operations. Climate-related physical risks may be acute or chronic. Acute physical risks are those that are event-driven, including increased frequency and severity of extreme weather events, such as heavy snowfall, heavy rainfall, floods, landslides, fires, hurricanes, cyclones, tornados, tropical storms, ice storms, and extreme temperatures. Chronic physical risks are longer-term shifts in climate patterns, such as long-term changes in precipitation patterns, or sustained higher temperatures, which may cause sea level rises or chronic heat waves.

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Our assets are exposed to potential damage or other negative impacts from these kinds of events, which could result in reduced revenue from business disruption or reduced capacity and may also lead to increased costs due to repairs and required adaptation measures. Such events may also result in personal injury, loss of life 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 continue to experience climate-related physical risks in the future, potentially with increasing frequency or severity.

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

Policy and legal risks
Policy and legal risks may result from evolving government policy, legislation, regulations and regulatory decisions focused on climate change, as well as changing political and public opinion, stakeholder opposition, legal challenges, litigation and regulatory proceedings. Foreign and domestic governments continue to evaluate and implement policy, legislation, and regulations regarding reduction of GHG emissions, adaptation to climate change, and transition to a lower-carbon economy. Such policies, laws and regulations vary at the federal, state, provincial and municipal levels in which Enbridge operates and are continually evolving. The implementation of these measures may be accelerated by international multilateral agreements, increasing physical impacts of climate change, and changing political and public opinion. Enbridge is currently required to adhere to a number of carbon-pricing mechanisms, including explicit carbon prices (i.e., in BC) and implicit carbon prices (i.e., Canadian federal OBPS). In Canada, the federal government has proposed new clean electricity regulations and is considering options to cap and cut oil and gas sector GHG emissions, which may impact our business. Such evolving policy, legislation and regulation could impact commodity demand and the overall energy mix we deliver and may result in significant expenditures and resources, as well as increased costs for our customers. In recent years, there has been an increase in climate-related regulatory action and litigation which has the potential to adversely impact our reputation, business, operations and financial results.

Technology risks
Our success in executing our strategic plan, including adapting to the energy transition over time and attaining our GHG emissions reduction goals and targets, depends, in part, on technology (including technology still under development), innovation and continued diversification with renewable power and other lower-carbon energy infrastructure as well as modernization of our infrastructure, all of which could require significant capital expenditures and resources, that could materially differ from our original estimates and expectations. There is also a risk that GHG emissions reduction technology does not materialize as expected, making it more difficult to reduce emissions, or that political or public opinion regarding such technologies continues to evolve.

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Market risks
Climate change concerns, increased demand for lower-carbon and zero-emissions energy, alternative and new energy sources and technologies, changing customer behavior and reduced energy consumption could impact the demand for our services or securities. In recent years, there has been a push toward certain investors decreasing the carbon intensity of their portfolios and pressure for banks and insurance providers to reduce or cease support for oil and natural gas and related infrastructure businesses and projects. Potential impacts include increased costs to manage these risks, adverse impacts to our access to and cost of capital, and reduced demand for, or value of, our securities. The pace and scale of the transition to a lower-carbon economy may pose a risk if Enbridge diversifies either too quickly or too slowly. Similarly, uncertainty in market signals, such as abrupt and unexpected shifts in energy costs and demands, including due to climate change concerns, can impact revenue through reduced throughput volumes on our pipeline transportation systems.

Reputational risks
Companies across all sectors and industries are facing changing expectations or increasing scrutiny from stakeholders related to their approach to climate change and GHG emissions. Companies in the energy industry are experiencing stakeholder opposition to both existing and new infrastructure, as well as organized opposition to oil and natural gas extraction and shipment of oil and natural gas products. If we are not able to achieve our GHG emissions reduction goals and targets, are not able to meet future climate, emissions or other regulatory or reporting requirements, or are not able to meet or manage current and future expectations and issues regarding climate change that are important to our stakeholders, it could negatively impact our reputation and, in turn, our business, operations or financial results.

Disclosure risks
Enbridge currently provides certain climate-related disclosures, and from time to time, establishes and publicly announces goals and commitments related to climate change, including reduction of GHG emissions. Standards and processes for climate-related disclosure, setting goals and targets, and measuring and reporting on progress are still developing for our sector and continue to evolve. Our internal controls and processes also continue to evolve, and our climate-related disclosures, goals and targets are based on assumptions that are subject to change. Aligning with evolving requirements has required and may continue to require us to incur significant costs. There can be no assurance that our current or future disclosures and goals, the pathways by which we plan to reach our goals, or the methodologies that we currently use to measure and report on progress, will align with new and evolving standards and processes, legal requirements or expectations of stakeholders. Such misalignment may result in reputational harm, regulatory action or other legal action.

RISKS RELATED TO OPERATIONAL DISRUPTION OR CATASTROPHIC EVENTS

Operation of complex energy infrastructure involves many hazards and risks that may adversely affect our business, financial results and the environment.
These operational risks include adverse weather conditions, natural disasters, accidents, the breakdown or failure of equipment or processes, and lower than expected levels of operating capacity and efficiency. These operational risks could be catastrophic in nature.

Operational risk is also intensified by climate change. Climate change presents physical risks that may affect the safety and reliability of our operations. These include acute physical risks, such as heavy snowfall, heavy rainfall, floods, landslides, fires, hurricanes, cyclones, tornados, tropical storms, ice storms, and extreme temperatures, and chronic physical risks, such as long-term changes in precipitation patterns, or sustained higher temperatures.

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Our assets and operations are exposed to potential damage or other negative impacts from these operational risks, which could result in reduced revenue from business disruption or reduced capacity and may also lead to increased costs due to repairs and required adaptation measures. Such events have led to, and could in the future lead to, rupture or release of product from our pipeline systems and facilities, resulting in damage to property and the environment, personal injury or loss of life, which could result in substantial losses for which insurance may not be sufficient or available and for which we may bear part or all of the cost.

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

We have experienced such events in the past, and expect to continue to incur significant costs in preparing for or responding to operational risks and events. We expect to continue to experience climate-related physical risks, potentially with increasing frequency and severity, and we cannot guarantee that we will not experience catastrophic or other events in the future. In addition, we could be subject to litigation and significant fines and penalties from regulators in connection with any such events.

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

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

Cyber attacks and other cybersecurity incidents pose threats to our technology systems and could materially adversely affect our business, operations, reputation or financial results.
Our business is dependent upon information systems and other digital technologies for controlling our plants, pipelines and other assets, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations.

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Cybersecurity risks have increased in recent years as a result of the proliferation of new technologies and the increased sophistication of cyber attacks and financially motivated cybercrime, as well as due to international and domestic political factors including geopolitical tensions, armed hostilities, war, civil unrest, sabotage, terrorism and state-sponsored or other cyber espionage. Human error or malfeasance can also contribute to a cyber incident, and cyber attacks can be internal as well as external and occur at any point in our supply chain. Because of the critical nature of our infrastructure and our use of information systems and other digital technologies to control our assets, we face a heightened risk of cyber attacks, such as ransomware, theft, misplaced or lost data, programming errors, phishing attacks, denial of service attacks, acts of vandalism, computer viruses, malware, hacking, malicious attacks, software vulnerabilities, employee errors and/or malfeasance, or other attacks, security or data breaches or other cybersecurity incidents. Cyber threat actors have attacked and threatened to attack energy infrastructure, and various government agencies have increasingly stressed that these attacks are targeting critical infrastructure, including pipelines, public utilities, and power generation, and are increasing in sophistication, magnitude, and frequency. Additionally, these risks may escalate during periods of heightened geopolitical tensions. New cybersecurity legislation, regulations and orders have been recently implemented or proposed, resulting in additional actual and anticipated regulatory oversight and compliance requirements, which will require significant internal and external resources. We cannot predict the potential impact to our business of potential future legislation, regulations or orders relating to cybersecurity.

We have experienced an increase in the number of attempts by external parties to access our systems or our company data without authorization, and we expect this trend to continue. Although we devote significant resources and security measures to prevent unwanted intrusions and to protect our systems and data, whether such data is housed internally or by external third parties, we and our third party vendors have experienced and expect to continue to experience cyber attacks of varying degrees in the conduct of our business. To-date, these prior cyber attacks have not, to our knowledge, had a material adverse effect on our business, operations or financial results. However, there is a risk that any such incidents could have a material adverse effect on us in the future.

Our technology systems or those of our vendors or other service providers are expected to become the target of further cyber attacks or security breaches which could compromise our data and systems or our access thereto by us, our customers or others, affect our ability to correctly record, process and report transactions, result in the loss of information, or cause operational disruption or incidents. There can be no assurance that our business continuity plans will be completely effective in avoiding disruption and business impacts.Furthermore, we and some of our third-party service providers (who may in turn also use third-party service providers) collect, process or store sensitive data in the ordinary course of our business, including personal information of our employees, residential gas distribution customers, land owners and investors, as well as intellectual property or other proprietary business information of ours or our customers or suppliers.We and some of our third-party services providers will process increasing amounts of personal information upon the closing of the previously announced acquisitions of gas utilities in the US, due to their large residential customer bases.

As a result of the foregoing, we could experience loss of revenues, repair, remediation or restoration costs, regulatory action, fines and penalties, litigation, breach of contract or indemnity claims, cyber extortion, ransomware, implementation costs for additional security measures, loss of customers, customer dissatisfaction, reputational harm, be liable under laws that protect the privacy of personal information, other negative consequences, or other costs or financial loss.These risks may be heightened, and the consequences magnified, upon closing of the Acquisitions. Regardless of the method or form of cyber attack or incident, any or all of the above could materially adversely affect our reputation, business, operations or financial results.

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In addition, a cyber attack could occur and persist for an extended period without detection. Any investigation of a cyber attack or other security incident may be inherently unpredictable, and it would take time before the completion of any investigation and availability of full and reliable information. During such time, we may not know the extent of the harm or how best to remediate it, and certain errors or actions could be repeated or compounded before they are discovered and remediated, all or any of which could further increase the costs and consequences of a cyber attack or other security incident, and our remediation efforts may not be successful. The inability to implement, maintain and upgrade adequate safeguards could materially and adversely affect our results of operations, cash flows, and financial condition. Moreover, recent rulemakings may require us to disclose information about a cybersecurity incident before it has been completely investigated or remediated in full or even in part. As cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

Furthermore, media reports about a cyber attack or other significant security incident affecting Enbridge, whether accurate or not, or, under certain circumstances, our failure to make adequate or timely disclosures to the public, law enforcement, other regulatory agencies or affected individuals following any such event, whether due to delayed discovery or otherwise, could negatively impact our operating results and result in other negative consequences, including damage to our reputation or competitiveness, harm to our relationships with customers, partners, suppliers, investors, and other third parties, interruption to our management, remediation or increased protection costs, significant litigation or regulatory action, fines or penalties, all of which could materially adversely affect our business, operations, reputation or financial results.

Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war, and other civil unrest or activism could adversely affect our business, operations or financial results.
Terrorist attacks and threats (which may take the form of cyber attacks), escalation of military activity, armed hostilities, war, sabotage, or civil unrest or activism may have significant effects on general economic conditions and may cause fluctuations in consumer confidence and spending and market liquidity, each of which could adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the US or Canada, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic critical infrastructure targets, such as energy-related assets, are at greater risk of cyber attack and may be at greater risk of other future attacks than other targets in the US and Canada. Enbridge’s infrastructure and projects under construction could be direct targets or indirect casualties of a cyber or physical attack. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced demand for our products and services, new legislation or public policy or increased stringency thereof, or denial or delay of permits and rights-of-way.

Pandemics, epidemics or infectious disease outbreaks, such as the COVID-19 pandemic, may adversely affect local and global economies and our business, operations or financial results.
Disruptions caused by pandemics, epidemics or infectious disease outbreaks could materially adversely affect our business, operations, financial results and forward-looking expectations. Governments' emergency measures to combat the spread could include restrictions on business activity and travel, as well as requirements to isolate or quarantine. The duration and magnitude of such impacts will depend on many factors that we may not be able to accurately predict. COVID-19 and government responses interrupted business activities and supply chains, disrupted travel, and contributed to significant volatility in the financial and commodity markets.

Disruptions related to pandemics, epidemics or infectious disease outbreaks could have the effect of heightening many of the other risks described in this Item 1A. Risk Factors.

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RISKS RELATED TO OUR BUSINESS AND INDUSTRY

There are utilization risks with respect to our assets.
With respect to our Liquids Pipelines assets, we are exposed to throughput risk on the Canadian Mainline, 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 and global production and consumption. These shifts can lead to fluctuations in commodity prices and price differentials, which could result in our system not being fully utilized in some areas. Other factors affecting system utilization include operational incidents, regulatory restrictions, system maintenance, and increased competition.

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

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

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

Competition may result in a reduction in demand for our services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected.
Our Liquids Pipelines business faces competition from competing carriers available to ship liquid hydrocarbons to markets in Canada, the US and internationally and from proposed pipelines that seek to access basins and markets currently served by our Liquids Pipelines. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. The liquids transported in our pipelines currently, or are expected to increasingly, compete with other emerging alternatives for end-users, including, but not limited to, electricity, electric batteries, biofuels, and hydrogen. Additionally, we face competition from alternative storage facilities. Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The natural gas transported in our business also competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. Our Renewable Power Generation business faces competition in the procurement of long-term power purchase agreements and from other fuel sources in the markets in which we operate. Competition in all of our businesses, including competition for new project development opportunities, could have a negative impact on our business, financial condition or results of operations.

Completion of our secured projects and maintenance programs are subject to various regulatory, operational and market risks, which may affect our ability to drive long-term growth.
Our project execution continues to face challenges with intense scrutiny on regulatory and environmental permit applications, politicized permitting, public opposition including protests, action to repeal permits, and resistance to land access. We have experienced permit denials, in particular, in relation to necessary maintenance on the Line 5 Pipeline on the Bad River Reservation in northern Wisconsin based on a stated desire of the Bad River Band to shut down the pipeline.

Continued challenges with global supply chains have created unpredictability in materials cost and availability. Labor shortages and inflationary pressures have increased costs of engineering and construction services.

Other events that can and have delayed project completion and increased anticipated costs include contractor or supplier non-performance, extreme weather events or geological factors beyond our control.

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Changing expectations of stakeholders regarding ESG and climate change practices could erode stakeholder trust and confidence, damage our reputation and influence actions or decisions about our company and industry and have negative impacts on our business, operations or financial results.
Companies across all sectors and industries are facing changing expectations or increasing scrutiny from stakeholders related to their approach to ESG matters of greatest relevance to their business and to their stakeholders. For energy companies, climate change, GHG emissions, safety and stakeholder and Indigenous relations remain primary focus areas, while other environmental elements such as biodiversity, human rights, and supply chain are ascendant. Companies in the energy industry are experiencing stakeholder opposition to new and existing infrastructure, as well as organized opposition to oil and natural gas extraction and shipment of oil and natural gas products. Changing expectations of our practices and performance across these ESG areas may impose additional costs or create exposure to new or additional risks. We are also exposed to the risk of higher costs, delays, project cancellations, loss of ability to secure new growth opportunities, new restrictions or the cessation of operations of existing pipelines due to increasing pressure on governments and regulators, and legal action, such as the legal challenges to the operation of Line 5 in Michigan and Wisconsin.

Our operations, projects and growth opportunities require us to have strong relationships with key stakeholders, including local communities, Indigenous groups and others directly impacted by our activities, as well as governments, regulatory agencies, investors and investor advocacy groups, investment funds, financial institutions, insurers and others, which are increasingly focused on ESG practices and performance. Enhanced public awareness of climate change has driven an increase in demand for lower-carbon and zero-emissions energy. There have been efforts in recent years affecting the investment community, including certain investors increasing investments in lower-carbon assets and businesses while decreasing the carbon intensity of their portfolios through, among other measures, divestments of companies with high exposure to GHG-intensive operations and products. Certain stakeholders have also pressured commercial and investment banks and insurance providers to reduce or stop financing and providing insurance coverage to oil and natural gas and related infrastructure businesses and projects. Managing these risks requires significant effort and resources. Potential impacts could also include changing investor sentiment regarding investment in Enbridge, which could impair our access to and increase our cost of capital, including penalties associated with our sustainability-linked financing and could adversely impact demand for, or value of, our securities.

Over the past year, geopolitical uncertainty, slowing Canadian and US economies and continuing inflationary pressures have underscored the critical need for access to secure, affordable energy.
The pace and scale of the transition to a lower-emission economy may pose a risk if Enbridge diversifies either too quickly or too slowly. Similarly, unexpected shifts in energy demands, including due to climate change concerns, can impact revenue through reduced throughput volumes on our pipeline transportation systems.

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We have long been committed to strong ESG practices, performance and reporting, and in 2020 introduced a set of ESG goals to strengthen transparency and accountability. The goals include increasing diversity and inclusion within our organization and reducing GHG emissions from our operations to net-zero by 2050, with corporate and business unit action plans aligned to our strategic priority to adapt to the energy transition over time. The costs associated with meeting our ESG goals, including our GHG emissions reduction goals, could be significant. There is also a risk that some or all of the expected benefits and opportunities of achieving our ESG goals may fail to materialize, may cost more than anticipated to achieve, may not occur within the anticipated time periods or may no longer meet changing stakeholder expectations. Similarly, there is a risk that emissions reduction technologies do not materialize as expected making it more difficult to reduce emissions. If we are not able to achieve our ESG goals, are not able to meet current and future climate, emissions or related reporting requirements of regulators, or are unable to meet or manage current and future expectations regarding issues important to investors or other stakeholders (including those related to climate change), it could erode stakeholder trust and confidence, which could negatively impact our reputation, business, operations or financial results.

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

One or all of the Acquisitions may not occur on the terms contemplated in the applicable Purchase and Sale Agreement or at all, or may not occur within the expected time frame, which may negatively affect the benefits we expect to obtain from the Acquisitions.
We cannot provide any assurance that the Acquisitions will be completed in the manner, on the terms and on the time frame currently anticipated, or at all. Completion of each of the Acquisitions is subject to the satisfaction or waiver of a number of conditions as set forth in the applicable Purchase and Sale Agreement that are beyond our control and may prevent, delay or otherwise materially adversely affect its completion.

The success of the Acquisitions will depend on, among other things, our ability to integrate the US gas utilities into our business in a manner that facilitates growth opportunities and achieves anticipated results. There is a significant degree of difficulty and management distraction inherent in the process of integrating an acquisition, including challenges integrating certain operations and functions (including regulatory functions), technologies, organizations, procedures, policies and operations, addressing differences in the business cultures of Enbridge and the US gas utilities and retaining key personnel. The integration may be complex and time consuming and involve delays or additional and unforeseen expenses. The integration process and other disruptions resulting from the Acquisitions may also disrupt our ongoing business.

Any failure to realize the anticipated benefits of the Acquisitions, additional unanticipated costs or other factors could negatively impact our earnings or cash flows, decrease or delay any beneficial effects of the Acquisitions and negatively impact our business, financial condition and results of operations.

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Our insurance coverage may not fully cover our losses in the event of an accident, natural disaster or other hazardous event, and we may encounter increased cost arising from the maintenance of, or lack of availability of, insurance.
Our operations are subject to many hazards inherent in our industry as described in this Item 1A. Risk Factors. We maintain an insurance program for us, our subsidiaries and certain of our affiliates to mitigate a certain portion of our risks. However, not all potential risks arising from our operations are insurable, or are insured by us as a result of availability, high premiums and for various other reasons. Enbridge self-insures a significant portion of certain risks through our wholly-owned captive insurance subsidiaries, and Enbridge’s insurance coverage is subject to terms and conditions, exclusions and large deductibles or self-insured retentions which may reduce or eliminate coverage in certain circumstances.

Enbridge’s insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, terms, policy limits and/or deductibles can vary substantially. We can give no assurance that we will be able to maintain adequate insurance in the future at rates or on other terms we consider commercially reasonable. In such case, we may decide to self-insure additional risks.

A significant self-insured loss, uninsured loss, a loss significantly exceeding the limits of our insurance policies, a significant delay in the payment of a major insurance claim, or the failure to renew insurance policies on similar or favorable terms could materially and adversely affect our business, financial condition and results of operations.

Our business is exposed to changes in market prices including interest rates and foreign exchange rates. Our risk management policies cannot eliminate all risks and may result in material financial losses. In addition, any non-compliance with our risk management policies could adversely affect our business, operations or financial results.
Our use of debt financing exposes us to changes in interest rates on both future fixed rate debt issuances and floating rate debt. While our financial results are denominated in Canadian dollars, many of our businesses have foreign currency revenues or expenses, particularly the US dollar. Changes in interest rates and foreign exchange rates could materially impact our financial results.

We use financial derivatives to manage risks associated with changes in foreign exchange rates, interest rates, commodity prices, power prices and our share price to reduce volatility of our cash flows. Based on our risk management policies, substantially all of our financial derivatives are associated with an underlying asset, liability and/or forecasted transaction and not intended for speculative purposes.

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

To the extent that we hedge our exposure to market prices, we will forego the benefits we would otherwise experience if these were to change in our favor. In addition, hedging activities can result in losses that might be material to our financial condition, results of operations and cash flows. Such losses have occurred in the past and could occur in the future. See Part II, Item 7A. Quantitative and Qualitative Disclosures about Market Risk and Item 8. Financial Statements and Supplementary Data for a discussion of our derivative instruments and related hedging activities.

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

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

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

Our Liquids Pipelines growth rate and results may be indirectly affected by commodity prices.
Wide commodity price basis between Western Canada and global tidewater markets have negatively impacted producer netbacks and margins in the past years that largely resulted from pipeline infrastructure takeaway capacity from producing regions in Western Canada and North Dakota which are operating at capacity. A protracted long-term outlook for low crude oil prices could result in delay or cancellation of future projects.

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

Our Energy Services and Gas Transmission and Midstream results may be adversely affected by commodity price volatility.
Within our US Midstream assets, we hold investments in DCP and Aux Sable, which are engaged in the businesses of gathering, treating, processing and selling natural gas and natural gas liquids. The financial results of these businesses are directly impacted by changes in commodity prices. To a lesser degree, the financial results of our US Transmission business are subject to fluctuation in power prices which impact electric power costs associated with operating compressor stations.

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Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Changing market conditions that impact the prices at which we buy and sell commodities have in the past limited margin opportunities and impeded Energy Services' ability to cover capacity commitments and could do so again in the future. Other market conditions, such as backwardation, have likewise limited margin opportunities.

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

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

RISKS RELATED TO GOVERNMENT REGULATION AND LEGAL RISKS

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

Within the US and in Canada, pipeline companies continue to face opposition from anti-energy/anti-pipeline activists, Indigenous and tribal groups and communities, citizens, environmental groups, and politicians concerned with the safety of pipelines and their potential environmental effects. In the US, the EPA redefined the Waters of the United States to align with the U.S. Supreme Court’s May 25, 2023 Sackett v. EPA decision that limits the scope of waters regulated by the Clean Water Act, issued new rules under Section 401 of the Clean Water Act broadening the scope of state review for water quality certifications, released rules on methane control and reporting, Cross-state Ozone Pollution (The Good Neighbor Plan), and the Power Plant Rule. The Council for Environmental Quality published immediately applicable guidance for conducting analyses under the National Environmental Policy Act (NEPA), followed by a new rule governing implementation of NEPA in federal actions that may significantly change environmental scope and cost assessments. The FERC has focused on the relationship between natural gas and electric power generation, particularly in connection with reliability issues during severe weather events. The PHMSA issued a draft rule on leak detection and repair. Federal agencies also issued guidance on how environmental justice concerns should be considered and addressed. Many other regulations adopted during the previous US presidential administration are being challenged in multiple courts and some have been overturned by reviewing courts. The current US administration may take further action to modify or reverse regulations that were promulgated by the previous US administration.

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In March of 2023, the Supreme Court of Canada heard the Attorney General of Canada’s appeal of the Alberta Court of Appeal’s non-binding decision that the federal Impact Assessment Act (IAA) is unconstitutional. The IAA includes impact assessment requirements that could apply to either federally or provincially regulated pipeline projects that fall within prescribed criteria or that the federal Minister of Environment otherwise designates for review. The potential for any pipeline project to be subject to IAA requirements adds significant uncertainty as to regulatory timelines and outcomes. The Alberta Court of Appeal found that the IAA is an impermissible federal overreach into provincial jurisdiction that would amount to a de facto expropriation of provincial natural resources and proprietary interests by the federal government. The Supreme Court of Canada issued its decision on October 13, 2023, with a majority of the court (5-2) finding that the federal impact assessment regime is outside of the federal Parliament’s authority and that the IAA should focus more narrowly on effects within federal jurisdiction. The decision is a non-binding advisory reference case, so the IAA and associated regulations are not "struck down"; however, the federal government will take the Supreme Court of Canada’s guidance and in collaboration with provinces and Indigenous groups, will seek to amend the IAA so that it is constitutional. The resulting amendments could impact the risks and timing of potential future regulatory approvals and the scope of federal review of intraprovincial pipeline projects.

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

If we are unable to obtain or maintain all required environmental regulatory approvals and permits for our operating assets and projects or if there is a delay in obtaining any required environmental regulatory approvals or permits, the operation of existing facilities or the development of new facilities could be prevented, delayed, or become subject to additional costs. Failure to comply with environmental laws and regulations may result in the imposition of civil or criminal fines, penalties and injunctive measures affecting our operating assets. We expect that changes in environmental laws and regulations, including those related to climate change, GHG emissions and climate-related disclosure, could result in a material increase in our cost of compliance with such laws and regulations, such as costs to monitor and report our emissions and install new emission controls to reduce emissions. We may not be able to include some or all of such increased costs in the rates charged for utilization of our pipelines or other facilities.

Our operations are subject to operational regulation and other requirements, including compliance with easements and other land tenure documents, and failure to comply with applicable regulations and other requirements could have a negative impact on our reputation, business, operations or financial results.
Operational risks relate to compliance with applicable operational rules and regulations mandated by governments, applicable regulatory authorities, or other requirements that may be found in easements, permits, or other agreements that provide a legal basis for our operations, breaches of which could result in fines, penalties, awards of damages, operating restrictions (including shutdown of lines) and an overall increase in operating and compliance costs.

We do not own all of the land on which our pipelines, facilities and other assets are located and we obtain the rights to construct and operate our pipelines and other assets from third parties or government entities. In addition, some of our pipelines, facilities and other assets cross Indigenous lands pursuant to rights-of-way or other land tenure interests. Our loss of these rights, including through our inability to renew them as they expire, could have an adverse effect on our reputation, operations and financial results. We have experienced litigation in relation to certain Line 5 and other easements; refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates.
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Regulatory scrutiny over our assets and operations has the potential to increase operating costs or limit future projects. Regulatory enforcement actions issued by regulators for non-compliant findings can increase operating costs and negatively impact reputation. Potential regulatory changes and legal challenges could have an impact on our future earnings from existing operations and the cost related to the construction of new projects. Regulators' future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which we operate. While we seek to mitigate operational regulation risk by actively monitoring and consulting on potential regulatory requirement changes with the respective regulators directly, or through industry associations, and by developing response plans to regulatory changes or enforcement actions, such mitigation efforts may be ineffective or insufficient. While we believe the safe and reliable operation of our assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators or other government officials to make unilateral decisions that could disrupt our operations or have an adverse financial impact on us.

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

Our Renewable Power Generation assets in Canada and the US are subject to directives, regulations, and policies of federal, provincial and state governments. These measures are variable and can change as a result of, among other things, tax rate changes and a change in the government, which can have a negative impact on our commercial arrangements.

Our Renewable Power Generation assets in Europe (France, Germany and the UK) are also subject to the directives, regulations and policies established and enforced by the EU and the UK government. These measures are variable and can include price controls, caps and demand reduction goals, all of which can have a negative impact on our revenues and earnings.

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We are subject to changes in our tax rates, the adoption of new US, Canadian or international tax legislation or exposure to additional tax liabilities.
We are subject to taxes in the US, Canada and numerous foreign jurisdictions. Due to economic and political conditions, tax rates in various jurisdictions may be subject to significant change. Our effective tax rates could be affected by changes in the mix of earnings in countries with differing statutory tax rates, changes in the valuation of deferred tax assets and liabilities, or changes in tax laws or their interpretation. In particular, Canada and other OECD countries have introduced a minimum tax rate to be applied on a global basis.The final legislation and list of the participating countries remains uncertain.In addition, the US enacted the Inflation Reduction Act in 2022 however key regulations still remain outstanding that could impact the interpretation of that act. 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, or by other legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved or new matters could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could adversely affect our financial results or affect our reputation. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for a discussion of certain legal proceedings with recent developments.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

Cybersecurity risk management, strategy and governance
Risk oversight and management is a key role for the Board and its committees. The Board is responsible for identifying and understanding Enbridge’s principal risks and ensuring that appropriate systems are implemented to monitor, manage and mitigate those risks. The committees of the Board have oversight over risks within their respective mandates.

Oversight of cybersecurity is integrated into the responsibilities of the Board. The Audit, Finance and Risk Committee (the AFRC) provides oversight of cybersecurity matters, particularly as they relate to financial risk and controls, integrity of financial data and public disclosures, and security of the cyber landscape across data and digital. The Safety and Reliability Committee (SRC) has oversight responsibility for security (physical, data and cyber) including as it relates to operational risk and controls, safety, operations integrity and reliability, and asset operations.

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Management provides regular reports to the Board at every meeting to review our top risks, identify trends and help manage risk. This includes quarterly reports to the AFRC and SRC on cybersecurity matters. In addition, on an annual basis management prepares and provides to the Board and its committees a corporate risk assessment (CRA), which analyzes and prioritizes enterprise-wide risks (including cybersecurity), highlighting top risks and trends. The annual CRA is an integrated enterprise-wide process. We assess and rank risks based on impact and probability, and we strive to ensure that mitigation measures are appropriately designed, prioritized and resourced. The CRA report is reviewed by the Board committees with responsibility for the risk category relevant to their mandate and is provided to the Board, which coordinates Enbridge's overall risk management approach. Complementary to the CRA, management prepares and provides to the SRC an annual top operational risk report that highlights the highest consequence operational risks across Enbridge and includes further detail on the risks and their treatment. This information helps inform the Board about the potential impact of top operational risks and that appropriate treatments are in place to manage those risks.

Cybersecurity has been identified as a top risk as attacks against participants in our industry have continued to increase in sophistication and frequency over the years. Cybersecurity risk is described in Item 1A. Risk Factors.

Enbridge’s management is responsible for the implementation of risk management strategies and monitoring performance. The technology and information services (TIS) function is centralized under the Senior Vice President & Chief Information Officer (CIO), who has over two decades of international leadership in the business of technology. We also engage independent third parties to assess our cybersecurity program, track their recommendations and use those to further improve the program. Reporting to the CIO is the Chief Information Security Officer who is in charge of our cybersecurity program and oversees the 24x7x365 Security Operations Center (SOC).

We conduct continuous assessments of our cybersecurity standards, perform regular tests of our ability to respond and recover, and monitor for potential threats. To further mitigate threats, we collaborate with governments and regulatory agencies, and take part in external events to learn and share. Our workforce participates in regular security awareness training, including exercises to build capabilities to identify and report suspect phishing emails to our SOC. In the last year, we continued to expand the cybersecurity training and simulated testing we administer to high-risk groups within the organization. A tailored cybersecurity training course has been implemented for team members in operational technology roles, and we have increased the frequency of phishing simulation tests.

We have a cybersecurity third party risk management program, which is an evolving, cross-functional program to help assess and mitigate risks from third party vendors and other service providers. Our cybersecurity team also uses several layers of defense and protection technologies, cybersecurity experts, and automated alerting and response mechanisms to reduce risk to Enbridge.

Although cybersecurity risks have not materially affected us, including our business strategy, results of operations or financial condition, to date, we have experienced an increasing number of cybersecurity threats in recent years. For more information about the cybersecurity risks we face, see the risk factor entitled "Cyber attacks and other cybersecurity incidents pose threats to our technology systems and could materially adversely affect our business, operations, reputation or financial results." in Item 1A. Risk Factors.
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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 I. Item 1. Business.

In general, our systems are located on land owned by others and are operated under easements and rights-of-way, licenses, leases or permits that have been granted by private land-owners, Indigenous communities, 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. The remainder of these compressor stations and other assets, like meter and valve stations, and underground gas storage fields, are used by us under easements, leases or permits.

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

ITEM 3. LEGAL PROCEEDINGS

We are involved in various legal and regulatory actions and proceedings which arise in the ordinary course of business. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations. Refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of certain legal proceedings with recent developments.

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

On October 17, 2022, four separate comprehensive enforcement resolutions were announced with the Minnesota Pollution Control Agency, Minnesota Department of Natural Resources (DNR), Fond du Lac Band of Lake Superior Chippewa, and Minnesota Attorney General’s Office related to alleged violations that occurred during construction of Line 3 Replacement (L3R). The Minnesota Attorney General filed a misdemeanor criminal charge for the taking of water without a permit at the Clearbrook aquifer, with this charge against us to be dismissed following one year of compliance with the state water appropriation rules. As part of its ongoing post-construction monitoring activities for L3R, Enbridge reported groundwater flow near Moose Lake in Aitkin County to the DNR. Enbridge has completed the agency approved corrective action at the site.

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 2, 2024, there were 73,123 registered shareholders of record of Enbridge common stock. A substantially greater number of holders of Enbridge common stock are 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, 2023.

Recent Sales of Unregistered Equity Securities
None.

Issuer Purchases of Equity Securities
PeriodTotal number of shares purchasedAverage price paid per shareTotal number of shares purchased as part of publicly announced plans or programs
Maximum number of shares that may yet be purchased under the plans or programs1
October 2023
(October 1 - October 31)
— N/A— 25,433,807 
November 2023
(November 1 - November 30)
— N/A— 25,433,807 
December 2023
(December 1 - December 31)
— N/A— 25,433,807 
1On January 4, 2023, the TSX approved our normal course issuer bid (NCIB), which commenced on January 6, 2023 and expired on January 5, 2024. Our NCIB permitted us to purchase, for cancellation, up to 27,938,163 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion through the facilities of the TSX, the NYSE and other designated exchanges and alternative trading systems.

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Total Shareholder Return
The following graph reflects the comparative changes in the value from January 1, 2019 through December 31, 2023 of $100 invested in (1) Enbridge Inc.’s common shares traded on the TSX, (2) the S&P/TSX Composite index, (3) the S&P 500 index, (4) our US peer group (comprising, by stock symbols, CNP, D, DTE, DUK, EPD, ET, KMI, MMP, NEE, NI, OKE, PAA, PCG, SO, SRE and WMB) and (5) our Canadian peer group (comprising, by stock symbols, CU, FTS, PPL and TRP). The amounts included in the table were calculated assuming the reinvestment of dividends.

Total Shareholder Return_Graph_2023.jpg

 January 1,
2019
December 31,
 20192020202120222023
Enbridge Inc.100.00 129.34 109.69 142.87 162.72 157.79 
S&P/TSX Composite100.00 122.88 129.76 162.32 152.83 170.79 
S&P 500 Index100.00 131.49 155.68 200.37 164.08 207.21 
US Peers1
100.00 118.76 101.11 124.27 139.24 145.15 
Canadian Peers100.00 131.71 108.28 135.12 140.43 142.20 
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 2023 and 2022 items and year-over-year comparisons between 2023 and 2022. For discussion of 2021 items and year-over-year comparisons between 2022 and 2021, 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, 2022.

RECENT DEVELOPMENTS

MAINLINE TOLLING AGREEMENT
Enbridge Inc. (Enbridge) has reached an agreement on a negotiated settlement with shippers for tolls on its Mainline System. The Mainline Tolling Settlement (MTS) covers both the Canadian and US portions of the Mainline and would see the Mainline continuing to operate as a common carrier system available to all shippers on a monthly nomination basis. The MTS is subject to regulatory approval and the term is seven and a half years through the end of 2028, with revised interim tolls effective on July 1, 2023.

The MTS includes:

an International Joint Toll (IJT), for heavy crude oil movements from Hardisty to Chicago, comprised of a Canadian Mainline Toll of $1.65 per barrel plus a Lakehead System Toll of US$2.57 per barrel, plus the applicable Line 3 Replacement (L3R) surcharge;
toll escalation for operation, administration, and power costs tied to US consumer price and power indices;
tolls that continue to be distance and commodity adjusted, and utilize a dual currency IJT; and
a financial performance collar providing incentives for Enbridge to optimize throughput and cost, but also providing downside protection in the event of extreme supply or demand disruptions or unforeseen operating cost exposure. This performance collar is intended to ensure the Mainline earns 11% to 14.5% returns, on a deemed 50% equity capitalization, which is similar to the returns earned on average during the previous tolling agreement.

Approximately 70% of Mainline deliveries are tolled under this settlement, while approximately 30% of deliveries are tolled on a full path basis to markets downstream of the Mainline. The other continuing feature is that the Mainline toll flexes up or down US$0.035 per barrel for 50,000 barrel per day changes in throughput.

The expected financial outcome from this settlement is in line with previously reported financial results after taking into consideration the previously recognized provision, inflationary cost adjustments and increased volumes. Enbridge filed an application with the Canada Energy Regulator (CER) for approval of the MTS on December 15, 2023, with unanimous support from its Representative Stakeholder Group. The CER indicated in its process letter that no dissenting comments were received by January 19, 2024 and that it may decide on the application or it may establish further process steps.

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On May 24, 2023, Enbridge filed an Offer of Settlement with the Federal Energy Regulatory Commission (FERC) for the Lakehead System (the Lakehead System Settlement). In addition to resolving litigation related to the Index portion of the Lakehead System rate, the Lakehead System Settlement also includes a depreciation truncation date of December 31, 2048 for the rate base applicable to the Index and Facilities Surcharge and agreement on the terms for future recovery through the Facilities Surcharge of costs related to two Line 5 projects: the Wisconsin Relocation Project and the Straits of Mackinac Tunnel. The Lakehead System Settlement was certified by the Settlement Judge on June 23, 2023 and was approved by the FERC Commissioners on November 27, 2023. Lakehead System tolls were revised effective December 1, 2023 to reflect the terms of the Lakehead System Settlement.

ACQUISITIONS
Acquisition of Renewable Natural Gas (RNG) Facilities
On January 2, 2024, through a wholly-owned US subsidiary, we acquired the first six Morrow Renewables operating landfill gas-to-RNG production facilities located in Texas and Arkansas for total consideration of $1.4 billion (US$1.1 billion), of which $0.5 billion (US$0.4 billion) was paid at close and $0.9 billion (US$0.7 billion) is payable within two years. The total consideration for all seven facilities is $1.6 billion (US$1.2 billion). Combined RNG production of the facilities is approximately 4.5 bcf per year. The acquired assets align with and advance our low-carbon strategy.

Fox Squirrel Solar
On November 15, 2023, we acquired a 50% interest in a newly formed partnership with EDF Renewables North America to participate in the initial phase of a solar power facility in Ohio. Cash consideration includes an upfront payment of $157 million (US$115 million) and subsequent capital commitments up to $398 million (US$291 million). Investments past the first phase are contingent on certain conditions being met. An additional payment of $164 million (US$123 million) was made at Phase 1 in-service in December 2023.

Hohe See and Albatros Offshore Wind Facilities
On November 3, 2023, we acquired an additional 24.45% interest in the Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities (the Offshore Wind Facilities), through the acquisition of a 49% interest in Enbridge Renewable Infrastructure Investments S.à r.l (ERII), for $391 million (€267 million) of cash and assumed debt of $524 million (€358 million), bringing our interest in the Offshore Wind Facilities to 49.9%. The Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities are located approximately 100 kilometers off the northern coast of Germany and came into service in 2019 and 2020, respectively.

Aitken Creek Gas Storage
On November 1, 2023, through a wholly-owned Canadian subsidiary, we acquired a 93.8% interest in Aitken Creek Gas Storage Facility and a 100% interest in Aitken Creek North Gas Storage Facility (collectively, Aitken Creek), located in BC, Canada, for $400 million, subject to other customary closing adjustments (the Aitken Creek Acquisition). Aitken Creek is the only underground natural gas storage facility in BC and connects to all major natural gas pipelines in western Canada. The Aitken Creek Acquisition enables us to continue to meet regional energy needs and to support increasing demand for liquefied natural gas (LNG) exports.

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US Gas Utilities
On September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina for an aggregate purchase price of $19.1 billion (US$14.0 billion), comprised of $12.8 billion (US$9.4 billion) of cash consideration and $6.3 billion (US$4.6 billion) of assumed debt, subject to customary closing adjustments (together, the Acquisitions). If completed, the Acquisitions will create North America's largest natural gas utility platform delivering over 9 billion cubic feet (bcf) per day to approximately 7 million customers across multiple regulatory jurisdictions. The Acquisitions are expected to close in 2024, subject to the satisfaction of customary closing conditions including the receipt of certain regulatory approvals, which are not cross-conditional.

On September 8, 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions. Refer to Financing Update for further details on the debt issuances and credit facility obtained to support the Acquisitions.

Tres Palacios Holdings LLC
On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for $451 million (US$335 million) of cash. Tres Palacios is a natural gas storage facility located in the US Gulf Coast and its infrastructure serves Texas gas-fired power generation and LNG exports, as well as Mexico pipeline exports. Tres Palacios is comprised of three natural gas storage salt caverns with a total FERC-certificated working gas capacity of approximately 35 billion bcf and also owns an integrated 62-mile natural gas header pipeline system, with eleven inter- and intrastate natural gas pipeline connections.

ASSET MONETIZATION
Disposition of Alliance Pipeline and Aux Sable
On December 13, 2023, we announced that Enbridge has entered into a definitive agreement to sell our 50.0% interest in the Alliance Pipeline and our interest in Aux Sable (including 42.7% interest in Aux Sable Midstream LLC and Aux Sable Liquid Products L.P., and 50% interest in Aux Sable Canada LP) to Pembina Pipeline Corporation for $3.1 billion, including approximately $0.3 billion of non-recourse debt, subject to customary closing adjustments. Closing is expected to occur in the first half of 2024, subject to the receipt of regulatory approvals and satisfaction of customary closing conditions. The sales proceeds will fund a portion of the Acquisitions and be used for debt reduction.

GAS TRANSMISSION AND MIDSTREAM PROCEEDINGS
Texas Eastern Transmission
The Stipulation and Agreement for Texas Eastern Transmission, LP’s (Texas Eastern) consolidated 2021 rate cases was approved by the FERC on November 30, 2022, and became effective on January 1, 2023. Texas Eastern received FERC approval on April 3, 2023 to implement the settled rates and other settlement provisions.

Maritimes & Northeast Pipeline
The toll settlement agreement for the Canadian portion of the Maritimes & Northeast (M&N) Pipeline (M&N Canada) expired in December 2023. M&N Canada reached a toll settlement with shippers for the effective period from January 1, 2024 to December 31, 2025. On November 28, 2023, M&N Canada filed the 2024 - 2025 toll settlement agreement with the CER for review and approval. A CER decision is expected in the first quarter of 2024.

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GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS
Incentive Regulation Rate Application
In October 2022, Enbridge Gas Inc. (Enbridge Gas) filed its application with the Ontario Energy Board (OEB) to establish a 2024 through 2028 Incentive Regulation (IR) rate setting framework. The application initially sought approval in two phases to establish 2024 base rates (Phase 1) on a cost-of-service basis and to establish a price cap rate setting mechanism (Phase 2) to be used for the remainder of the IR term. A third phase (Phase 3) has been established with the OEB as part of the Phase 1 Partial Settlement Proposal (Settlement Proposal).

On August 17, 2023, the OEB approved the Settlement Proposal to support the determination of just and reasonable rates effective January 1, 2024. Items resolved in whole or in part include:

additions to rate base up to and including 2022;
interest rates on debt and return on equity;
deferral and variance accounts;
Indigenous engagement; and
rate implementation approach for 2024.
On December 21, 2023, the OEB issued its Decision and Order on Phase 1 (Phase 1 Decision). The decision addressed three main areas: energy transition, Enbridge Gas Distribution Inc. and Union Gas Limited amalgamation and harmonization issues, and other issues. The Phase 1 Decision included the following key findings or orders:

energy transition risk requires Enbridge Gas to carry out a risk assessment to consider further risk mitigation measures in three areas: system access and expansion capital spending, system renewal capital spending and depreciation policy;
our 2024 capital plan must be reduced by $250 million with a focus on monitoring, repair and life extension of our assets and a further $50 million of capitalized indirect overhead costs must be expensed, escalating to $250 million per year during the IR term with an offsetting adjustment to revenues in each year;
all new small volume customers wishing to connect to natural gas pay their full connection costs as an upfront charge rather than through rates over time effective January 1, 2025;
approval of a harmonized depreciation methodology that reduced the level of depreciation sought and adjusted asset lives including extensions of service life for certain asset classes;
an increase in equity thickness from 36% to 38% effective for 2024; and
January 1, 2024 will be the effective date for 2024 rates.

The issues addressed in the Settlement Proposal and the Phase 1 Decision resulted in the following items not approved for future recovery, and the subsequent impairments recognized for the year ended December 31, 2023:

a portion of undepreciated capital projects removed from 2024 rate base of $41 million;
undepreciated integration capital costs removed from 2024 rate base of $84 million; and
pre-2017 Union Gas Limited related pension balances of $156 million.
Enbridge Gas filed a Notice of Appeal in the Ontario Divisional Court on January 22, 2024 regarding four aspects of the Phase 1 Decision: small volume customer revenue horizon, the 2024 capital plan reduction, the extension of service life for certain asset classes and equity thickness. On January 29, 2024 Enbridge Gas also filed a Notice of Motion with the OEB requesting the OEB to review and vary five aspects of the Phase 1 Decision: small volume customer revenue horizon, the 2024 capital plan reduction, integration capital, depreciation and equity thickness. The outcome of these proceedings is uncertain.

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The Phase 1 Decision results in interim rates, pending phases 2 and 3 of the proceeding, resolution of the Notice of Appeal, Notice of Motion and any possible legislative steps that could be undertaken by the Government of Ontario further to the Ontario Minister of Energy's December 22, 2023 news release. Phase 2 will establish and determine the incentive rate mechanism for the remainder of the rebasing term, and gas cost and unregulated storage cost allocation. Phase 3 will address cost allocation and the harmonization of rates and rate classes between legacy rate zones.

Purchase Gas Variance
The Purchase Gas Variance Account (PGVA) captures the difference between actual and forecasted natural gas prices reflected in rates. Account balances are typically recovered or refunded over a prospective 12-month period through Quarterly Rate Adjustment Mechanism (QRAM) applications.

In March 2023, the April 1, 2023 QRAM application was filed and approved by the OEB, which included an adjustment to the prior rate mitigation approved as part of the July 1, 2022 QRAM. The recovery of the outstanding PGVA balance from the extended recovery period approved as part of the July 1, 2022 QRAM will now be completed by March 31, 2024. In June, September and December 2023, the July 1, 2023, October 1, 2023, and January 1, 2024 QRAM applications, respectively, were filed and approved by the OEB with no adjustments to the prior period rate mitigation plans and did not include any additional rate mitigation measures.

As at December 31, 2023, Enbridge Gas' PGVA liability balance was $16 million.

FINANCING UPDATE
We completed long-term debt issuances totaling US$8.5 billion and $3.9 billion during the year ended December 31, 2023, including aggregate amounts of US$2.3 billion of 10-year sustainability-linked senior notes in March 2023 and $400 million of 10-year sustainability-linked medium-term notes in May 2023.

We increased our credit facilities in March 2023 by approximately $500 million. During our annual renewal process, we renewed and extended approximately $15.4 billion of our credit facilities with maturities ranging from 2024-2028.

In September 2023, we obtained commitments for a US$9.4 billion senior unsecured bridge term loan credit facility to support the Acquisitions. The commitment for this facility was subsequently reduced to nil  as at December 31, 2023 as a result of the September 2023 $4.6 billion equity offering, the September 2023 subordinated long-term debt issuances, and the November 2023 senior notes long-term debt issuances.

In September 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions.

Our 2023 financing activities have provided significant liquidity that we expect will enable us to fund our current portfolio of capital projects and acquisitions without requiring access to the capital markets for the next 12 months should market access be restricted or pricing be unattractive. Refer to Liquidity and Capital Resources.

As at December 31, 2023, after adjusting for the impact of floating-to-fixed interest rate swap hedges, less than 5% of our total debt is exposed to floating rates. Refer to Part II. Item 8. Financial Statements and Supplementary Data - Note 23 - Risk Management and Financial Instruments for more information on our interest rate hedging program.

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NORMAL COURSE ISSUER BID
On January 4, 2023, the Toronto Stock Exchange (TSX) approved our normal course issuer bid (NCIB), which commenced on January 6, 2023 and expired on January 5, 2024. Our NCIB permitted us to purchase, for cancellation up to 27,938,163 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion through the facilities of the TSX, the New York Stock Exchange and other designated exchanges and alternative trading systems.

RESULTS OF OPERATIONS
Year ended December 31,202320222021
(millions of Canadian dollars, except per share amounts)   
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
   
Liquids Pipelines9,499 8,364 7,897 
Gas Transmission and Midstream4,264 3,126 3,671 
Gas Distribution and Storage1,592 1,827 2,117 
Renewable Power Generation149 262 508 
Energy Services(37)(417)(313)
Eliminations and Other837 (1,124)356 
Earnings before interest, income taxes and depreciation and amortization1
16,304 12,038 14,236 
Depreciation and amortization(4,613)(4,317)(3,852)
Interest expense(3,812)(3,179)(2,655)
Income tax expense(1,821)(1,604)(1,415)
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests133 65 (125)
Preference share dividends(352)(414)(373)
Earnings attributable to common shareholders5,839 2,589 5,816 
Earnings per common share attributable to common shareholders2.84 1.28 2.87 
Diluted earnings per common share attributable to common shareholders2.84 1.28 2.87 
1 Non-GAAP financial measures.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Year ended December 31, 2023 compared with year ended December 31, 2022
Earnings attributable to common shareholders increased by $3.2 billion due to certain infrequent or other non-operating factors, primarily explained by the following:

the absence in 2023 of a goodwill impairment of $2.5 billion relating to our Gas Transmission reporting unit;
a non-cash, net unrealized derivative fair value gain of $1,127 million ($856 million after-tax) in 2023, compared with a net unrealized loss of $1,246 million ($950 million after-tax) in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange, interest rate, and commodity risks;
the absence in 2023 of: an asset impairment loss of $227 million ($173 million after-tax) to our Magic Valley Wind Farm (Magic Valley); an asset impairment loss of $183 million ($137 million after-tax) on the US and Canadian components of the interstate pipeline within the North Dakota System of our Bakken System, an impairment of $44 million ($34 million after-tax) for lease assets due to office relocation plans, and an asset impairment loss of $40 million ($30 million after-tax) relating to MacKay River line within our Alberta Regional Oil Sands System;
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a gain of $151 million ($129 million after-tax) and a deferred tax adjustment of $69 million were recognized as a result of Southern Lights Pipeline's (Southern Lights) discontinuation of regulatory accounting;
the absence in 2023 of a transaction cost of $114 million in relation to our investment purchase in the Woodfibre LNG project;
a deferred income tax recovery of $104 million related to a tax adjustment on asset impairments;
a non-cash, net unrealized gain of $73 million ($55 million after-tax) in 2023, compared with a net unrealized loss of $27 million ($21 million after-tax) in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as to manage the exposure to movements in commodity prices;
the receipt of a litigation claim settlement of $68 million ($52 million after-tax) in 2023; and
a non-cash, net unrealized gain of $35 million ($33 million after-tax) in 2023, compared with a net unrealized loss of $25 million ($22 million after-tax) in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries.

The factors above were partially offset by:

the absence in 2023 of a gain of $1,076 million ($732 million after-tax) on the closing of the joint venture merger transaction with Phillips 66 (P66) realigning our indirect economic interests in Gray Oak Pipeline LLC (Gray Oak) and DCP Midstream, LP (DCP);
a realized loss of $638 million ($479 million after-tax) due to termination of foreign exchange hedges, as foreign exchange risks inherent within the Competitive Toll Settlement (CTS) framework are not present in the negotiated Mainline tolling agreement;
an impairment loss of $261 million ($20 million after-tax and net of noncontrolling interest) to our Chapman Ranch wind facilities;
an impairment of $281 million ($232 million after-tax) recognized to certain capital projects, capital costs and pension balances in the fourth quarter of 2023 as a result of the OEB's Phase 1 Decision on Enbridge Gas' application;
a deferred tax adjustment of $120 million as a result of deregulation of parts of the Canadian Mainline including Line 9 and L3R;
a provision adjustment and settlement of $124 million ($95 million after-tax) related to a litigation matter;
the absence in 2023 of a gain of $118 million ($89 million after-tax) on Texas Eastern recorded to reflect a settlement with a transportation customer undergoing bankruptcy;
an asset retirement loss of $86 million ($65 million after-tax) related to our Alberta Regional Oil Sands System;
an impairment loss of $82 million ($63 million after-tax) to certain Offshore equity investments in our Gas Transmission and Midstream segment; and
transaction costs of $31 million ($24 million after-tax) incurred as a result of the Acquisitions.

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

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After taking DCFinto consideration the factors above, the remaining $51 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:

higher contributions from the Mainline System in our Liquids Pipelines segment driven by increased volumes due to increased crude demand, net of C$9,440a lower L3R surcharge and lower Mainline System tolls as a result of revised interim tolls effective July 1, 2023;
higher contributions from our Liquids Pipelines segment due to increased ownership of the Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and the Enbridge Ingleside Energy Center (EIEC) due to higher demand;
the recognition of revenues in our Gas Transmission and Midstream segment attributable to the Texas Eastern rate case settlement;
higher distribution charges at our Gas Distribution and Storage segment resulting from increases in rates and customer base as well as higher demand in the contract market;
higher contributions from our Energy Services segment primarily due to the expiration of transportation commitments and favorable margins due to less pronounced market structure backwardation; and
the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, as compared to 2022; partially offset by
a reduction in earnings from our Gas Transmission and Midstream segment primarily due to our decreased interest in DCP as a result of a joint venture merger transaction with P66 that closed in the third quarter of 2022;
higher operating and administrative costs in our Gas Transmission and Midstream and Gas Distribution and Storage segments;
lower commodity prices impacting the DCP and Aux Sable joint ventures in our Gas Transmission and Midstream segment;
higher interest expense primarily due to higher interest rates and higher average principal; and
higher depreciation and amortization expense as a result of several projects placed into service in the second half of 2022.

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

Transportation and other services revenues of $19.8 billion, $18.5 billion and $16.2 billion for the years ended December 31, 2023, 2022 and 2021, 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 $4.8 billion, $5.7 billion and $4.0 billion for the years ended December 31, 2023, 2022 and 2021, 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.

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Commodity sales revenues of $19.0 billion, $29.2 billion and $26.9 billion for the years ended December 31, 2023, 2022 and 2021, respectively, were generated primarily through our Energy Services operations. Energy Services includes the purchase and sale of crude oil, natural gas, power and NGL to generate a margin, which is typically a small fraction of gross revenue. Sales revenue generated from these operations 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
Year ended December 31,202320222021
(millions of Canadian dollars)   
Earnings before interest, income taxes and depreciation and
amortization
9,499 8,364 7,897 

Year ended December 31, 2023 compared with year ended December 31, 2022
EBITDA was positively impacted by $500 million due to certain infrequent or other non-operating factors, primarily explained by the following:

a non-cash, net unrealized gain of $607 million in 2023, compared with a net unrealized loss of $183 million in 2022, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks;
a gain of $151 million recognized as a result of Southern Lights' discontinuation of regulatory accounting;
the absence in 2023 of: a total asset impairment loss of $183 million on the US and Canadian components of the interstate pipeline within the North Dakota System of our Bakken System, and an asset impairment loss of $40 million relating to MacKay River line within our Alberta Regional Oil Sands System, partially offset by an asset retirement loss in 2023 of $86 million related to our Alberta Regional Oil Sands System; and
the receipt of a litigation claim settlement of $68 million in 2023; partially offset by
a realized loss of $638 million due to termination of foreign exchange hedges, as foreign exchange risks inherent within the CTS framework are not present in the negotiated Mainline tolling agreement.

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After taking into consideration the factors above, the remaining $635 million increase is primarily explained by the following significant business factors:

higher Mainline System ex-Gretna average throughput of 3.1 million barrels per day (mmbpd) in 2023 as compared to 3.0 mmbpd in 2022, and higher Line 9 deliveries to eastern Canada driven by higher crude demand, net of a lower L3R surcharge and lower Mainline System tolls as a result of revised interim Mainline tolls effective July 1, 2023;
higher contributions from the Gulf Coast and Mid-Continent System due primarily to increased ownership of Gray Oak Pipeline and Cactus II Pipeline acquired in the second half of 2022 and the EIEC due to higher demand; and
the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, as compared to 2022; partially offset by
higher power costs as a result of increased volumes and power prices.

GAS TRANSMISSION AND MIDSTREAM
Year ended December 31,202320222021
(millions of Canadian dollars)   
Earnings before interest, income taxes and depreciation and amortization4,264 3,126 3,671 

Year ended December 31, 2023 compared with year ended December 31, 2022
EBITDA was positively impacted by $1.2 billion due to certain infrequent or other non-operating factors primarily explained by the following:

the absence in 2023 of a goodwill impairment of $2.5 billion; partially offset by
the absence in 2023 of: a gain of $1,076 million on the closing of the joint venture merger transaction with P66 realigning our effective economic interests in Gray Oak and DCP, and a gain of $118 million on Texas Eastern recorded for a customer bankruptcy settlement;
a provision adjustment and settlement of $124 million related to a litigation matter; and
an impairment loss of $82 million to certain Offshore equity investments.

After taking into consideration the factors above, we saw a $19 million decrease, primarily explained by the following significant business factors:

a reduction in earnings from our investment in DCP as a result of our decreased interest due to the
joint venture merger transaction with P66 that closed during the third quarter of 2022;
higher operating and administrative costs;
lower commodity prices impacting our DCP and Aux Sable joint ventures;
lower AECO-Chicago basis differential impacting our investment in Alliance Pipeline, partially offset by
the favorable effect of translating US dollar earnings at a higher average exchange rate in 2023, as compared to 2022;
favorable contracting on our US Gas Transmission and Storage assets;
the recognition of revenues attributable to the Texas Eastern rate case settlement effective for 2023; and
contributions from the Tres Palacios acquisition in the second quarter of 2023 and Aitken Creek in the fourth quarter of 2023.

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GAS DISTRIBUTION AND STORAGE

Year ended December 31,202320222021
(millions of Canadian dollars)   
Earnings before interest, income taxes and depreciation and amortization1,592 1,827 2,117 

Year ended December 31, 2023 compared with year ended December 31, 2022
EBITDA was negatively impacted by $252 million due to an impairment of $281 million recognized to certain capital projects, capital costs and pension balances in the fourth quarter of 2023 as a result of the OEB's Phase 1 Decision.

After taking into consideration the factors above, the remaining $17 million increase is primarily explained by the following significant business factors:

higher distribution charges resulting from increases in rates and customer base, as well as higher demand in the contract market; partially offset by
when compared with the normal weather forecast embedded in rates, warmer than normal weather in 2023 negatively impacted 2023 EBITDA by approximately $86 million year over year; and
higher operating and administrative costs primarily due to higher pension related costs.

RENEWABLE POWER GENERATION

Year ended December 31,202320222021
(millions of Canadian dollars)   
Earnings before interest, income taxes and depreciation and amortization149 262 508 

Year ended December 31, 2023 compared with year ended December 31, 2022
EBITDA was negatively impacted by $122 million due to certain infrequent or non-operating factors, primarily explained by:

an impairment loss of $261 million to Chapman Ranch wind facilities, partially offset by the absence in 2023 of an impairment loss of $227 million to Magic Valley; and
a non-cash, net unrealized loss of $72 million in 2023, compared with a net unrealized gain of $8 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage commodity price risks.

After taking into consideration the negative factors above, the remaining $9 million increase is primarily explained by the following significant business factors:

fees earned on certain wind and solar development contracts;
higher contribution from the Hohe See and Albatros Offshore Wind Facilities as a result of the November 2023 acquisition of an additional 24.45% interest in these facilities; and
contributions from the Saint-Nazaire Offshore Wind Project, which reached full operating capacity in December 2022; partially offset by
lower energy pricing at European offshore wind facilities; and
weaker wind resources at Canadian and US onshore wind facilities.

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ENERGY SERVICES

Year ended December 31,202320222021
(millions of Canadian dollars)   
Loss before interest, income taxes and depreciation and amortization(37)(417)(313)

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, 2023 compared with year ended December 31, 2022
EBITDA was positively impacted by $117 million due to certain non-operating factors, primarily explained by a non-cash, net unrealized gain of $73 million in 2023, compared with a net unrealized loss of $27 million in 2022, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as to manage the exposure to movements in commodity prices.

After taking into consideration the factor above, the remaining $263 million increase is primarily explained by the following significant business factors:

expiration of certain less attractive transportation commitments;
more favorable margins realized on facilities where we hold capacity obligations and storage opportunities as compared to 2022; and
less pronounced market structure backwardation as compared to 2022.

ELIMINATIONS AND OTHER

Year ended December 31,202320222021
(millions of Canadian dollars)   
Earnings/(loss) before interest, income taxes and depreciation and amortization837 (1,124)356 

Eliminations and Other includes operating and administrative costs that are not allocated to business segments, the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. Eliminations and Other also includes the impact of new business development activities and corporate investments.

Year ended December 31, 2023 compared with year ended December 31, 2022
EBITDA was positively impacted by $1.9 billion due to certain infrequent or non-operating factors, primarily explained by:

a non-cash, net unrealized gain of $623 million in 2023, compared with a net unrealized loss of $1,090 million in 2022, reflecting changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;
the absence in 2023 of: $114 million of transaction costs in relation to our investment purchase in the Woodfibre LNG Project, and an impairment of $44 million for lease assets due to office relocation plans; and
a non-cash, net unrealized gain of $35 million in 2023, compared with a net unrealized loss of $25 million in 2022, reflecting changes in the mark-to-market value of equity fund investments held by our wholly-owned captive insurance subsidiaries; partially offset by
transaction costs of $31 million incurred as a result of the Acquisitions.

After taking into consideration the non-operating factors above, we saw a $18 million increase in EBITDA that is primarily explained by higher investment income from the pre-funding of the Acquisitions.
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GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS
The following table summarizes the status of our significant commercially secured projects, organized by business segment:
Enbridge's Ownership Interest
Estimated
Capital
Cost1
Expenditures
to Date
2
Status2
Expected
In-Service
Date
(Canadian dollars, unless stated otherwise)
GAS TRANSMISSION AND MIDSTREAM
1.
Texas Eastern Venice Extension Project3
100 %US$477 millionUS$170 millionUnder construction2023 - 2024
2.Texas Eastern Modernization100 %US$394 millionUS$37 millionPre-construction2025 - 2026
3.T-North Expansion100 %$1.2 billion$70 millionPre-construction2026
4.
Rio Bravo Pipeline5
100 %US$1.2 billionUS$66 millionPre-construction2026
5.
Woodfibre LNG6
30 %US$1.5 billionUS$310 millionUnder construction2027
6.
T-South Expansion4
100 %$4.0 billion$67 millionPre-construction2028
RENEWABLE POWER GENERATION
7.
Fécamp Offshore Wind7
17.9 %$692 million$528 millionUnder construction1Q-2024
(€471 million)(€362 million)
8.
Calvados Offshore Wind8
21.7 %$954 million$307 millionUnder construction2025
(€645 million)(€214 million)
9.Fox Squirrel Solar50 %US$406 millionUS$152 millionUnder construction2023-2024
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 and status of the project are determined as at December 31, 2023.
3Includes the $37 million Gator Express Project placed into service in August 2023. Total estimated capital cost consists of the reversal and expansion of Texas Eastern's Line 40 expected to be completed in 2024.
4Capital cost estimates will be updated prior to filing the regulatory applications.
5Rio Grande LNG has reached a final investment decision for three liquefaction trains. Current estimated capital cost is based on two liquefaction trains and an update to the estimated capital cost is expected to be provided in 2024.
6Our equity contribution is approximately US$893 million, with the remainder financed through non-recourse project level debt. Capital cost estimates will be updated prior to the 60% engineering milestone, at which point Enbridge's preferred return will be set.
7Our equity contribution is $103 million, with the remainder financed through non-recourse project level debt.
8Our equity contribution is $181 million, with the remainder financed through non-recourse project level debt.

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

GAS TRANSMISSION AND MIDSTREAM
The following commercially secured growth projects are currently in various stages of construction:

Texas Eastern Venice Extension Project A reversal and expansion of Texas Eastern’s Line 40 from its existing New Roads compressor station to a new delivery point with the proposed Gator Express pipeline just south of Texas Eastern’s Larose compressor station. The project is expected to deliver 1.5 billion cubic feet per day (bcf/d) of natural gas to Venture Global Plaquemines LNG, LLC’s LNG export facility located in Plaquemines Parish, Louisiana and is underpinned by long-term take or pay contracts.

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

T-North Expansion – An expansion of Westcoast Energy Inc.'s (Westcoast) BC Pipeline in northern BC that includes pipeline looping, additional compressor units and other ancillary station modifications to support 535 million cubic feet per day (mmcf/d) of additional capacity. The project will be underpinned by a cost-of-service commercial model with a target in-service date of 2026. On January 8, 2024, we filed the regulatory application with the CER.

Rio Bravo Pipeline – In July 2023, the Rio Grande LNG export facility, owned by NextDecade Corporation (NextDecade), reached a final investment decision. As a result, the construction on our previously announced Rio Bravo Pipeline project is anticipated to proceed after obtaining necessary regulatory approvals. The first phase of the Rio Bravo Pipeline is designed to transport 2.6 bcf/d of natural gas feedstock to NextDecade's Rio Grande LNG export facility in the Port of Brownsville, Texas. The project is expected to achieve commercial operations in 2026.

Woodfibre LNG Project Construction of liquefaction and floating storage facilities in Squamish, BC, as well as an expansion of the BC Pipeline System. The project is expected to be placed into service in 2027.

T-South Expansion – An expansion of Westcoast's BC Pipeline's T-South section that includes pipeline looping, additional compressor units and other ancillary station modifications to support 300 mmcf/d of additional capacity. The project is expected to be placed in service in 2028 and will be underpinned by a cost-of-service commercial model.

RENEWABLE POWER GENERATION
The following commercially secured growth projects are expected to be placed into service from 2023 to
2025:

Fécamp Offshore Wind Project – An offshore wind project that will be comprised of 71 wind turbines located off the northwest coast of France and is expected to generate approximately 500 megawatts (MW). Project revenues are underpinned by a 20-year fixed price power purchase agreement (PPA).

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

Fox Squirrel Solar – A fully contracted, ground-mounted solar facility in Ohio with expected installed capacity of approximately 577 MW. The initial phase successfully commenced operations in December 2023. We plan to invest in the following phases in 2024, assuming certain conditions are met. Project revenues are underpinned by a 20-year fixed price PPA.

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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 and acquisitions 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 maintaining sufficient liquidity through the use 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 17 - Debt and Note 26 - Leases for amounts outstanding at December 31, 2023, related to debt and leases.

Long-term contracts are contracts that we have signed for the purchase of services, pipe and other materials totaling $8.9 billion which are expected to be paid over the next five years. Remaining long-term contracts primarily consist of the following purchase obligations: firm capacity payments for natural gas and crude oil transportation and storage contracts, natural gas purchase commitments, service and product purchase obligations and power commitments.

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.

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$8.5 billion and $3.9 billion in 2023:

EntityIssuance dateType of issuanceAmount
(in millions of Canadian dollars, unless stated otherwise)
Enbridge Inc.March 2023Sustainability-linked senior notesUS$2,300
Enbridge Inc.March 2023Senior notesUS$700
Enbridge Inc.May 2023Medium-term notes$1,100
Enbridge Inc.May 2023Sustainability-linked medium-term notes$400
Enbridge Inc.September 2023Fixed-to-fixed subordinated notesUS$2,000
Enbridge Inc.September 2023Fixed-to-fixed subordinated notes$1,000
Enbridge Inc.November 2023Senior notesUS$3,500
Enbridge Gas Inc.October 2023Medium-term notes$1,000
Enbridge Pipelines Inc.August 2023Medium-term notes$350

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Credit Facilities, Ratings and Liquidity
To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities, inclusive of term loans, at December 31, 2023:
Maturity1
Total Facilities
Draws2
Available
(millions of Canadian dollars)    
Enbridge Inc.2024-20288,876 3,177 5,699 
Enbridge (U.S.) Inc.2025-20288,373 670 7,703 
Enbridge Pipelines Inc.20252,000 449 1,551 
Enbridge Gas Inc.20252,500 400 2,100 
Total committed credit facilities 21,749 4,696 17,053 
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.

In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to $2.5 billion and in July 21, 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, we renewed approximately $6.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2025, which includes a one-year term out provision from July 2024. We also renewed approximately $7.6 billion of our five-year credit facilities, extending the maturity dates to July 2028. Further, we extended our three-year credit facilities, extending the maturity dates to July 2026.

In September 2023, we obtained commitments for a US$9.4 billion senior unsecured bridge term loan credit facility to support the Acquisitions. The commitment for this facility was subsequently reduced to nil  as at December 31, 2023 as a result of the September 2023 $4.6 billion equity offering, the September 2023 subordinated long-term debt issuances, and the November 2023 senior notes long-term debt issuances.

In addition to the committed credit facilities noted above, we maintain $1.1 billion of uncommitted demand letter of credit facilities, of which $572 million was unutilized as at December 31, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 million was unutilized.

As at December 31, 2023, our net available liquidity totaled $23.0 billion (2022 - $10.0 billion), consisting of available credit facilities of $17.1 billion (2022 - $9.1 billion) and unrestricted Cash and cash equivalents of $5.9 billion (2022 - $861 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, 2023, we were in compliance with all debt covenants and expect to continue to comply with such covenants.
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Cash flow growth, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. In 2023, our credit ratings with DBRS Morningstar, Fitch Ratings, Moody's Investor Services, Inc. and Standard & Poor's were all affirmed. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to EBITDA.

There are no material restrictions on our cash. Total Restricted cash of $84 million, as reported in the Consolidated Statements of Financial Position, primarily includes cash collateral and future pipeline abandonment costs collected and held in trust. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative use by us.

Excluding current maturities of long-term debt, as at December 31, 2023 and 2022, we had a positive and negative working capital positions of $3.0 billion and $2.1 billion, respectively. In 2023, the major contributing factor to the positive working capital position was the increase in cash associated with pre-funding of the Acquisitions. In 2022, the major contributing factor to the negative working capital position was the current liabilities associated with our growth capital program.
SOURCES AND USES OF CASH
Year ended December 31,202320222021
(millions of Canadian dollars)   
Operating activities14,201 11,230 9,256 
Investing activities(6,043)(5,270)(10,657)
Financing activities(2,864)(5,428)1,236 
Effect of translation of foreign denominated cash and cash equivalents and restricted cash(216)55 (5)
Net change in cash and cash equivalents and restricted cash5,078 587 (170)

Significant sources and uses of cash for the years ended December 31, 2023 and 2022 are summarized below:

Operating Activities
Typically, the primary factors impacting cash provided by 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 infrequent or other non-operating factors, as discussed under Results of Operations, as well as Distributions from equity investments.

Investing Activities
Cash used in investing activities primarily relates to capital expenditures to execute our capital program, which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements. Cash used in investing activities is also impacted by acquisitions and dispositions as discussed under Recent Developments, and changes in contributions to, and distributions from, our equity investments.



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A summary of additions to property, plant and equipment for the years ended December 31, 2023, 2022 and 2021 is set out below:
Year ended December 31,202320222021
(millions of Canadian dollars)   
Liquids Pipelines1,158 1,418 4,051 
Gas Transmission and Midstream1,890 1,647 2,353 
Gas Distribution and Storage1,451 1,499 1,343 
Renewable Power Generation100 50 16 
Energy Services — 
Eliminations and Other55 33 54 
Total capital expenditures4,654 4,647 7,818 

2023
The increase in cash used in investing activities primarily resulted from the following factors:
the absence in 2023 of the proceeds received from the completion of a joint venture merger transaction for DCP Midstream, LLC in August 2022; and
higher cash outflows related to acquisitions in 2023 when compared to 2022.

The factors above were partially offset by higher distributions in 2023 mainly related to our investment in NEXUS Gas Transmission, LLC.

2022
The decrease in cash used in investing activities primarily resulted from the following factors:

lower capital expenditures due to the US L3R program that was placed into service in the fourth quarter of 2021;
lower cash outflows related to acquisitions in 2022 when compared to 2021; and
proceeds received from the completion of a joint venture merger transaction for DCP Midstream LLC in August 2022.

The factors above were partially offset by:

the absence in 2022 of proceeds received from dispositions in 2021 related to sale of our interest in Noverco Inc. in December 2021; and
increased investments held by our wholly-owned captive insurance subsidiaries.

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

2023
The decrease in cash used in financing activities primarily resulted from the following factors:

higher long-term debt issuances in 2023 when compared to the same period in 2022;
our public offering of common shares, which closed on September 8, 2023, resulting in the issuance of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion, which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions; and
the absence in 2023 of the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022, respectively.
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The factors above were partially offset by:

higher net commercial paper and credit facility repayments in 2023 when compared to the same period in 2022;
net repayments of short-term borrowings in 2023 when compared to net issuances in 2022;
the absence in 2023 of proceeds received from the sale of a non-operating interest in seven pipelines from our Regional Oil Sands System in October 2022;
higher long-term debt repayments in 2023 when compared to the same period in 2022; and
increased common share dividend payments primarily due to the increase in our common share dividend rate and an increase in the number of common shares outstanding.

2022
The increase in cash used in financing activities primarily resulted from the following factors:

net commercial paper and credit facility repayments in 2022 when compared to draws in 2021;
higher long-term debt repayments along with lower long-term debt issuances in 2022 when compared to 2021;
the redemption of Preference Shares, Series 17 and Series J in the first and second quarters of 2022, respectively;
the repurchase and cancellation of 2,737,965 common shares under our NCIB for approximately $151 million in 2022; and
increased common share dividend payments primarily due to the increase in our common share dividend rate.

The factors above were partially offset by:

proceeds received from the sale of a non-operating interest in seven pipelines from our Regional Oil Sands System in October 2022; and
the absence in 2022 of the redemption of Westcoast's preferred shares in the first quarter of 2021.

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

We do not have material off-balance sheet financing entities or structures, except for guarantee arrangements and financings entered into for our equity investments. For additional information on these commitments, please refer to Part II. Item 8. Financial Statements and Supplementary Data -Note 30 - Commitments and Contingencies and Note 12 - Variable Interest Entities.

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

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OUTSTANDING PREFERENCE SHARES
Characteristics of our outstanding preference shares are as follows:
Dividend Rate
Dividend1
Per Share Base
Redemption
Value2
Redemption and
Conversion
Option Date2,3
Right to
Convert
Into3,4
(Canadian dollars unless otherwise stated)
Preference Shares, Series A5.50 %$1.37500$25— — 
Preference Shares, Series B5.20 %$1.30052$25June 1, 2027Series C
Preference Shares, Series D5
5.41 %$1.35300$25March 1, 2028Series E
Preference Shares, Series F6
5.54 %$1.38452$25June 1, 2028Series G
Preference Shares, Series G7
6.96 %$1.90704$25June 1, 2028Series F
Preference Shares, Series H8
6.11 %$1.52800$25September 1, 2028Series I
Preference Shares, Series I9
7.19 %$1.81004$25September 1, 2028Series H
Preference Shares, Series L5.86 %US$1.46448US$25September 1, 2027Series M
Preference Shares, Series N6.70 %$1.67400$25December 1, 2028Series 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 110
6.70 %US$1.67592US$25June 1, 2028Series 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 1911
6.21 %$1.55300$25March 1, 2028Series 20
1The holder is entitled to receive a fixed cumulative quarterly preferential dividend, as declared by the Board of Directors. With the exception of Preference Shares, Series A, such fixed dividend rate resets every five years beginning on the initial Redemption and Conversion Option Date. Preference Shares, Series G and I contain a feature where the dividend rate resets on a quarterly basis. The Preference Shares, Series 19 contain a feature where the fixed dividend rate, when reset every five years, will not be less than 4.90%. No other series of preference shares has this feature.
2Preference Shares, Series A may be redeemed any time at our option. For all other series of preference shares, we may at our option, redeem all or a portion of the outstanding preference shares for the Per Share Base Redemption Value 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 Per Share Base Redemption Value.
4With the exception of Preference Shares, Series A, after the Redemption and Conversion Option Date, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in year) x three month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in year) x three month US Government treasury bill rate + 3.2% (Series M), 3.1% (Series 2), or 2.8% (Series 6).
5The quarterly dividend per share paid on Preference Shares, Series D was increased to $0.33825 from $0.27875 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.
6The quarterly dividend per share paid on Preference Shares, Series F was increased to $0.34613 from $0.29306 on June 1, 2023 due to reset of the annual dividend on June 1, 2023.
7On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G.
8The quarterly dividend per share paid on Preference Shares, Series H was increased to $0.38200 from $0.27350 on September 1, 2023 due to reset of the annual dividend on September 1, 2023.
9On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I.
10 The quarterly dividend per share paid on Preference Shares, Series 1 was increased to US$0.41898 from US$0.37182 on June 1, 2023 due to reset of the annual dividend on June 1, 2023.
11 The quarterly dividend per share paid on Preference Shares, Series 19 was increased to $0.38825 from $0.30625 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.

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DIVIDENDS
We have paid common share dividends in every year since we became a publicly traded company in 1953. In November 2023, we announced a 3.1% increase in our quarterly dividend to $0.9150 per common share, or $3.66 annualized, effective with the dividend payable on March 1, 2024, thereby declaring a dividend increase for 29 straight years.

For the years ended December 31, 2023 and 2022, total dividends paid were $7.3 billion and $7.0 billion, respectively, all of which were paid in cash and reflected in Cash Flows from Financing Activities in the Consolidated Statements of Cash Flows.

On November 28, 2023, our Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2024 to shareholders of record on February 15, 2024.
Dividend per share
Common Shares1
$0.91500 
Preference Shares, Series A$0.34375 
Preference Shares, Series B$0.32513 
Preference Shares, Series D$0.33825 
Preference Shares, Series F$0.34613 
Preference Shares, Series G2
$0.47676 
Preference Shares, Series H$0.38200 
Preference Shares, Series I3
$0.45251 
Preference Shares, Series LUS$0.36612 
Preference Shares, Series N4
$0.41850 
Preference Shares, Series P$0.27369 
Preference Shares, Series R$0.25456 
Preference Shares, Series 1US$0.41898 
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 19$0.38825 
1The quarterly dividend per common share was increased 3.1% to $0.9150 from $0.8875, effective March 1, 2024.
2The quarterly dividend per share paid on Preference Shares, Series G was increased to $0.47676 from $0.47245 on December 1, 2023 due to reset on a quarterly basis.
3The quarterly dividend per share paid on Preference Shares, Series I was increased to $0.45251 from $0.44814 on December 1, 2023 due to reset on a quarterly basis following the date of issuance.
4The quarterly dividend per share paid on Preference Shares, Series N was increased to $0.41850 from $0.31788 on December 1, 2023 due to reset of the annual dividend on December 1, 2023.


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SUMMARIZED FINANCIAL INFORMATION

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

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, 2023, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.
2As at December 31, 2023, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

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Enbridge Notes under Guarantees
USD Denominated1
CAD Denominated2
Floating Rate Senior Notes due 20243.950% Medium-term Notes due 2024
3.500% Senior Notes due 20242.440% Medium-term Notes due 2025
2.150% Senior Notes due 20243.200% Medium-term Notes due 2027
2.500% Senior Notes due 20255.700% Medium-term Notes due 2027
2.500% Senior Notes due 20256.100% Medium-term Notes due 2028
4.250% Senior Notes due 20264.900% Medium-term Notes due 2028
1.600% Senior Notes due 20262.990% Medium-term Notes due 2029
5.969% Senior Notes due 20267.220% Medium-term Notes due 2030
5.900% Senior Notes due 20267.200% Medium-term Notes due 2032
3.700% Senior Notes due 20276.100% Sustainability-Linked Medium-term Notes due 2032
6.000% Senior Notes due 20283.100% Sustainability-Linked Medium-term Notes due 2033
3.125% Senior Notes due 20295.360% Sustainability-Linked Medium-term Notes due 2033
6.200% Senior Notes due 20305.570% Medium-term Notes due 2035
2.500% Sustainability-Linked Senior Notes due 20335.750% Medium-term Notes due 2039
5.700% Sustainability-Linked Senior Notes due 20335.120% Medium-term Notes due 2040
4.500% Senior Notes due 20444.240% Medium-term Notes due 2042
5.500% Senior Notes due 20464.570% Medium-term Notes due 2044
4.000% Senior Notes due 20494.870% Medium-term Notes due 2044
3.400% Senior Notes due 20514.100% Medium-term Notes due 2051
6.700% Senior Notes due 20536.510% Medium-term Notes due 2052
5.760% Medium-term Notes due 2053
4.560% Medium-term Notes due 2064
1As at December 31, 2023, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$15.7 billion.
2As at December 31, 2023, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $11.0 billion.

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

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 31,2023
(millions of Canadian dollars)
Operating loss(149)
Earnings4,273
Earnings attributable to common shareholders3,921

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Summarized Combined Statements of Financial Position
December 31,20232022
(millions of Canadian dollars)
Cash and cash equivalents6,525 425
Accounts receivable from affiliates3,440 2,486
Short-term loans receivable from affiliates3,291 5,232
Other current assets491 969
Long-term loans receivable from affiliates45,702 43,873
Other long-term assets3,303 4,111
Accounts payable to affiliates2,264 1,375
Short-term loans payable to affiliates807 1,745
Trade payable and accrued liabilities743 716
Other current liabilities7,256 8,036
Long-term loans payable to affiliates35,556 37,626
Other long-term liabilities52,096 47,447

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

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

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

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

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

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

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

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

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

LEGAL AND OTHER UPDATES

LIQUIDS PIPELINES
Line 5 Easement (Bad River Band)
On July 23, 2019, the Bad River Band of the Lake Superior Tribe of Chippewa Indians (the Band) filed a complaint in the US District Court for the Western District of Wisconsin (the Court) over our Line 5 pipeline and right-of-way across the Bad River Reservation (the Reservation). Only a small portion of the total easements across 12 miles of the Reservation are at issue. The Band alleges that our continued use of Line 5 to transport crude oil and related liquids across the Reservation is a public nuisance under federal and state law and that the pipeline is in trespass on certain tracts of land in which the Band possesses ownership interests. The complaint seeks an Order prohibiting us from using Line 5 to transport crude oil and related liquids across the Reservation and requiring removal of the pipeline from the Reservation. Subsequently amended versions of the complaint also seek recovery of profits-based damages based on an unjust enrichment theory. Enbridge has responded to each claim in the initial and amended complaints with an answer, defenses and counterclaims.

On August 29, 2022, the Government of Canada released a statement formally invoking the dispute settlement provisions of the 1977 Transit Pipelines Treaty in respect of this litigation; reiterating its concerns about the uninterrupted transmission of hydrocarbons through Line 5. On September 7, 2022, the Court issued a decision on cross-motions for summary judgment. The Court determined that the Band's nuisance claim raised factual issues that could not be resolved on summary judgment. The Court further determined that Enbridge is in trespass on 12 parcels on the Reservation and that the Band is entitled to some measure of profits-based damages and to an injunction, with the level of damages and scope of the injunction to be determined at trial, which occurred October 24 through November 1, 2022.

On May 9, 2023, the Band filed an Emergency Motion for Injunctive Relief asking the Court to require Enbridge to purge and shutdown Line 5 on the Reservation due to significant erosion at the Meander. Enbridge responded and a hearing was held on May 18, 2023 in front of Judge Conley who indicated that he did not find the Band had proven imminence but his final ruling on all issues would be provided soon.
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On June 26, 2023, the Court issued its Final Order ruling that (1) Enbridge shall adopt and implement its 2022 Monitoring and Shutdown Plan with the Court's modifications by July 5, 2023; (2) Enbridge owes the Band $5,151,668 for past trespass on the 12 allotted parcels; (3) Enbridge must continue to pay money on a quarterly basis using the formula set in its Order as long as Line 5 operates in trespass on the 12 allotted parcels (approximately $400,000 per year); (4) Enbridge must cease operation of Line 5 on any parcel within the Band's tribal territory without a valid right of way by June 16, 2026 and thereafter arrange prompt, reasonable remediation at those sites; and (5) The Court declined to allow for the Relocation to be completed prior to having to cease operations. The Final Judgment was entered on June 29, 2023. Enbridge filed its Notice of Appeal on June 30, 2023 and the Band filed its Notice of Cross Appeal on July 27, 2023. On December 12, 2023, the 7th Circuit requested the US to file a brief in this appeal as amicus curiae to address the effect of the Agreement Between the US and Canada Concerning Transit Pipelines, 28 U.S.T. 7449 (1977), and any other issues that the US believes to be material. Briefing by the parties was complete on December 15, 2023. Oral argument is scheduled in February 2024, and we anticipate a decision in 2024.

Michigan Line 5 Dual Pipelines - Straits of Mackinac Easement
In 2019, the Michigan Attorney General (AG) filed a complaint in the Michigan Ingham County Circuit Court (the Circuit Court) that requests the Circuit Court to declare the easement granted in 1953 that we have for the operation of Line 5 in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of Line 5 in the Straits. On December 15, 2021, Enbridge removed the case to the US District Court in the Western District of Michigan (US District Court), where it was assigned to Judge Janet T. Neff. The removal of the AG's case to federal court followed a November 16, 2021 ruling which held that the similar (and now dismissed) 2020 lawsuit brought by the Governor of Michigan to force Line 5's shutdown raised important federal issues that should be heard in federal court. On December 21, 2021, the AG made a request to file a motion to remand the 2019 case, which the US District Court allowed on January 5, 2022. However, after full briefing, on August 18, 2022, Judge Neff denied the AG's motion to remand. On August 30, 2022, the AG filed a motion to certify the August 18 Order to pursue an appeal on the jurisdictional issue, which Enbridge opposed. On February 21, 2023, that motion was granted and shortly after, on March 2, 2023, the AG filed her Petition for Permission to Appeal in the 6th Circuit Court of Appeals (6th Circuit).

On July 21, 2023, the 6th Circuit granted the AG's Petition for Permission to appeal the US District Court's August 18 Order denying remand to state court. The 6th Circuit's briefing was completed by the end of 2023 and oral argument has been scheduled for March 2024. We anticipate a decision in 2024.

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

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.

On March 25, 2020, in response to amended complaints from the Tribes, the District Court found that the Army Corps' subsequent environmental review completed in August 2018 was also deficient and ordered the Army Corps to prepare an Environmental Impact Statement (EIS) to address unresolved controversy pertaining to potential spill impacts resulting from DAPL. On July 6, 2020, the District Court issued an order vacating the Army Corps' easement for DAPL and ordering that the pipeline be shut down by August 5, 2020. On that day, the US Court of Appeals for the District of Columbia Circuit stayed the District Court's July 6 order to shut down and empty the pipeline.

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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. The US Supreme Court subsequently denied the request of Dakota Access, LLC to review the decision that an EIS is required. The US Court of Appeals also determined that, absent an injunction proceeding, the District Court could not order DAPL's operations to cease. While not an issue before, 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.

The Army Corps earlier indicated that it did not intend to exercise its authority to bar DAPL's continued operation, notwithstanding the absence of an easement.

On September 8, 2023, the Army Corps issued its draft EIS, which assesses the impacts of DAPL under five alternative scenarios: denying the easement removing the pipeline; denying the easement and leaving the pipeline in place; granting the easement with the prior conditions (which allow for the ongoing operation, maintenance and ultimate removal of the pipeline and its related facilities); granting the easement with some new safety conditions; and rerouting the pipeline. The Army Corps did not identify a preferred alternative. The public comment period that commenced on the issuance of the draft EIS closed on December 13, 2023. The pipeline will remain operational while the environmental review process continues.

GAS TRANSMISSION AND MIDSTREAM
Aux Sable
The previously reported claim filed against Aux Sable by a counterparty to an NGL supply agreement was settled and discontinued during the fourth quarter of 2023. A provision was recognized for this claim in the third quarter of 2023.

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

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our consolidated financial statements are prepared in accordance with US GAAP, which requires 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.

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BUSINESS COMBINATIONS
We apply the provisions of Accounting Standards Codification 805 Business Combinations in accounting for our acquisitions. The acquired 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 identifiable 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 a corresponding offset to goodwill. Upon conclusion of the measurement period, or the final determination of values for assets acquired or liabilities assumed, whichever comes first, any subsequent adjustments are recorded to our Consolidated Statements of Earnings.

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

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

We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components, and whether the economic and regulatory characteristics are similar. Our reporting units are Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation. The Renewable Power Generation reporting unit had goodwill beginning in the third quarter of 2022.

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

The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit's carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using a discounted cash flow technique. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, expected future capital expenditures and working capital levels, as well as terminal value growth rates for the Liquids Pipelines, Gas Transmission, and Renewable Power Generation reporting units, and projected regulatory rate base and rate base multiple for the Gas Distribution and Storage reporting unit.
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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, 2023, we performed our annual goodwill impairment assessment which consisted of a qualitative assessment for the Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation reporting units and did not identify impairment indicators. Due to an impairment recorded in 2022 for the Gas Transmission reporting unit and the OEB decision on Phase 1 for Enbridge Gas, we performed a quantitative assessment for the Gas Transmission and Gas Distribution and Storage reporting units as at December 1, 2023, which did not result in the recognition of an impairment charge for either reporting unit. Also, we did not identify any indicators of goodwill impairment during the remainder of 2023.

The Gas Transmission reporting unit remains at risk as the quantitative test performed resulted in the fair value exceeding carrying value by less than 10% and once the Alliance Pipeline and Aux Sable disposition closes in 2024, the fair value of the reporting unit will decrease.

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 that we may not recover the carrying amount of our assets. We regularly monitor our businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, 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 qualitative or quantitative analysis of factors impacting the investment. If there is objective evidence of impairment, we determine whether the decline below carrying value is other-than-temporary. If the decline is determined to be other-than-temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the investment.

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

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

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REGULATORY ACCOUNTING
Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the CER, the FERC, the Alberta Energy Regulator, the BC Energy Regulator, the OEB and the Québec Régie de l'énergie. 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, amounts collected from customers in advance of costs being incurred, or 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 regulator. If there are changes in our assessment of the probability of recovery for a regulatory asset, we reduce its carrying amount to the balance that we expect to recover from customers in future periods through rates. If a regulator later excludes from allowable costs all or a part of costs that were capitalized as a regulatory asset, we reduce the carrying amount of the asset by the excluded amounts.

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. During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements effective 2025. We do not expect to renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline is no longer subject to rate-regulated accounting. As a result, the related regulatory liabilities, regulatory tax assets and associated regulatory deferred tax liabilities were derecognized.

As at December 31, 2023 and 2022, our regulatory assets totaled $5.7 billion and $6.5 billion, respectively, and regulatory liabilities totaled $3.8 billion.

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DEPRECIATION
Depreciation of property, plant and equipment, our largest asset with a net book value at December 31, 2023 and 2022, of $104.6 billion and $104.5 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 consolidated financial statements for the year ended December 31, 2023 of a 0.5% change in key pension and other postretirement benefits (OPEB) obligation assumptions:
 CanadaUnited States
 ObligationExpenseObligationExpense
(millions of Canadian dollars)    
Pension
Decrease in discount rate29712523
Decrease in expected return on assets215
Decrease in rate of salary increase(60)(5)(5)(1)
OPEB
Decrease in discount rate1515
Decrease in expected return on assets N/A N/A1

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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 Legal and Other Updates and 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 Other current liabilities 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. The discount rates used to estimate the present value of expected future cash flows for the years ended December 31, 2023 and 2022 ranged from 1.5% 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 fair value of ARO 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 trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues and Restricted long-term investments. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities.

CHANGES IN ACCOUNTING POLICIES

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.
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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 hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps and costless collars. These swaps have an average fixed rate of 4.1%.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via execution of floating-to-fixed interest rate swaps with an average swap rate of 3.5%.
Commodity Price Risk
Our earnings, cash flows and OCI 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 the revaluation of outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted stock 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).

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CFaR is a statistically derived measurement used to measure the maximum cash flow loss that could potentially result from adverse market price movements over a one month holding period for price sensitive non-derivative exposures and for derivative instruments we hold or issue as recorded in the Consolidated Statements of Financial Position as at December 31, 2023. 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, 2023 and 2022 CFaR was $100 million and $144 million or 0.9% and 1.3%, respectively, of estimated 12 month forward normalized cash flow.

LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. Our shelf prospectuses with securities regulators enable ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2023. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities. We also identify a variety of other potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.
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 the maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.
We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances.

FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivatives and other financial 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, 2023 and 2022, 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, 2023, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023 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, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.

Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also 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.

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Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Goodwill Impairment Assessment
As described in Notes 2 and 15 to the consolidated financial statements, the Company’s goodwill balance was $31,848 million at December 31, 2023. 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 discounted cash flow technique. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, expected future capital expenditures and working capital levels, as well as terminal value growth rates for the Liquids Pipelines, Gas Transmission and Midstream (Gas Transmission), and Renewable Power Generation reporting units, and projected regulatory rate base and rate base multiple for the Gas Distribution and Storage (Gas Distribution) reporting unit. Management performed a qualitative goodwill impairment assessment as of April 1, 2023 for the following reporting units: Liquids Pipelines, Gas Transmission, Gas Distribution and Renewable Power Generation and did not identify impairment indicators. Due to the Ontario Energy Board decision on Phase 1 for Enbridge Gas Inc., announced in December 2023, management performed a quantitative assessment for the Gas Distribution reporting unit as of December 1, 2023. In addition, management performed a quantitative assessment for the Gas Transmission reporting unit as of December 1, 2023. Neither assessment resulted in the recognition of an impairment charge of either reporting unit.

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The principal considerations for our determination that performing procedures relating to the goodwill impairment assessment is a critical audit matter are the significant judgments required by management when developing such significant assumptions as discount rates, projected operating income, expected future capital expenditures, terminal value growth rates, projected regulatory rate base and rate base multiple used to estimate the fair value of the Gas Transmission and Gas Distribution reporting units, as applicable, as of December 1, 2023. This led to a high degree of auditor judgment, effort and subjectivity in performing procedures to evaluate the reasonableness of management’s significant assumptions used in the quantitative assessment. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.These procedures included testing the effectiveness of controls relating to management’s quantitative goodwill impairment assessment, including controls over the determination of the fair value estimates of the Company’s reporting units. These procedures also included, among others, testing management’s process for developing the fair value estimates of the Gas Transmission and Gas Distribution reporting units.

Testing management’s process for developing the fair value estimates included evaluating the appropriateness of the discounted cash flow models; testing the completeness and accuracy of underlying data used in the models; and evaluating the reasonableness of significant assumptions used by management in determining the fair value estimates, including discount rates, projected operating income, expected future capital expenditures, projected regulatory rate base and rate base multiple and terminal value growth rates. Assessing the reasonableness of projected operating income, expected future capital expenditures and the projected regulatory rate base involved evaluating whether these significant assumptions were reasonable considering the current and past performance of the Company’s reporting units, external industry data and evidence obtained in other areas of the audit, as applicable. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of management’s discounted cash flow models and evaluating the reasonableness of significant assumptions used in the models, specifically discount rates, terminal value growth rates and the rate base multiple.


/s/PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Canada
February 9, 2024

We have served as the Company's auditor since 1949.
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ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS
Year ended December 31,202320222021
(millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales18,981 29,150 26,873 
Gas distribution sales4,839 5,653 4,026 
Transportation and other services19,829 18,506 16,172 
Total operating revenues (Note 4)
43,649 53,309 47,071 
Operating expenses
Commodity costs18,526 28,942 26,608 
Gas distribution costs2,840 3,647 2,094 
Operating and administrative8,600 8,219 6,712 
Depreciation and amortization4,613 4,317 3,852 
Impairment of long-lived assets419 541 — 
Impairment of goodwill (Note 15)
 2,465 — 
Total operating expenses34,998 48,131 39,266 
Operating income8,651 5,178 7,805 
Income from equity investments (Note 13)
1,816 2,056 1,600 
Gain on joint venture merger transaction (Note 13)
 1,076 — 
Other income/(expense) (Note 27)
1,224 (589)979 
Interest expense (Note 17)
(3,812)(3,179)(2,655)
Earnings before income taxes7,879 4,542 7,729 
Income tax expense (Note 24)
(1,821)(1,604)(1,415)
Earnings6,058 2,938 6,314 
(Earnings)/loss attributable to noncontrolling interests133 65 (125)
Earnings attributable to controlling interests6,191 3,003 6,189 
Preference share dividends(352)(414)(373)
Earnings attributable to common shareholders5,839 2,589 5,816 
Earnings per common share attributable to common shareholders (Note 6)
2.84 1.28 2.87 
Diluted earnings per common share attributable to common shareholders (Note 6)
2.84 1.28 2.87 
The accompanying notes are an integral part of these consolidated financial statements.
102


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Year ended December 31,202320222021
(millions of Canadian dollars)
Earnings6,058 2,938 6,314 
Other comprehensive income/(loss), net of tax
Change in unrealized gain on cash flow hedges220 847 162 
Change in unrealized gain/(loss) on net investment hedges409 (971)49 
Other comprehensive income/(loss) from equity investees6 (6)(12)
Excluded components of fair value hedges12 (35)(5)
Reclassification to earnings of loss on cash flow hedges14 143 235 
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts(18)(10)21 
Reclassification to earnings of (gain)/loss on equity investees 16 (62)
Actuarial gain/(loss) on pension and OPEB(130)312 394 
Foreign currency translation adjustments(1,728)4,406 (507)
Other comprehensive income/(loss), net of tax(1,215)4,702 275 
Comprehensive income4,843 7,640 6,589 
Comprehensive (income)/loss attributable to noncontrolling interests131 (21)(95)
Comprehensive income attributable to controlling interests4,974 7,619 6,494 
Preference share dividends(352)(414)(373)
Comprehensive income attributable to common shareholders4,622 7,205 6,121 
The accompanying notes are an integral part of these consolidated financial statements.
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ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Year ended December 31,202320222021
(millions of Canadian dollars, except per share amounts)
Preference shares (Note 20)
   
Balance at beginning of year6,818 7,747 7,747 
Redemption of preference shares (929)— 
Balance at end of year6,818 6,818 7,747 
Common shares (Note 20)
Balance at beginning of year64,760 64,799 64,768 
Shares issued, net of issue costs4,485 — — 
Shares issued on exercise of stock options3 53 31 
Shares issued on vesting of restricted stock units (RSU), net of tax12 — — 
Share purchases at stated value(80)(88)— 
Other (4)— 
Balance at end of year69,180 64,760 64,799 
Additional paid-in capital
Balance at beginning of year275 365 277 
Stock-based compensation71 36 28 
Stock options exercised(3)(50)(23)
Vested RSUs(20)— — 
Purchase of noncontrolling interest(28)(43)— 
Change in reciprocal interest — 98 
Other(27)(33)(15)
Balance at end of year268 275 365 
Deficit   
Balance at beginning of year(15,486)(10,989)(9,995)
Earnings attributable to controlling interests6,191 3,003 6,189 
Preference share dividends(352)(414)(373)
Common share dividends declared(7,423)(7,023)(6,818)
Dividends paid to reciprocal shareholder — 
Share purchases in excess of stated value(45)(63)— 
Balance at end of year(17,115)(15,486)(10,989)
Accumulated other comprehensive income/(loss) (Note 22)
Balance at beginning of year3,520 (1,096)(1,401)
Other comprehensive income/(loss) attributable to common shareholders, net of tax(1,217)4,616 305 
Balance at end of year2,303 3,520 (1,096)
Reciprocal shareholding
Balance at beginning of year — (29)
Change in reciprocal interest — 29 
Balance at end of year — — 
Total Enbridge Inc. shareholders' equity61,454 59,887 60,826 
Noncontrolling interests (Note 19)
   
Balance at beginning of year3,511 2,542 2,996 
Earnings/(loss) attributable to noncontrolling interests(133)(65)125 
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain/(loss) on cash flow hedges35 (28)(15)
Foreign currency translation adjustments(33)114 (15)
 2 86 (30)
Comprehensive income/(loss) attributable to noncontrolling interests(131)21 95 
Distributions(363)(259)(271)
Contributions11 1,105 15 
Redemption of noncontrolling interests — (293)
Purchase of noncontrolling interests2 55 — 
Other(1)47 — 
Balance at end of year3,029 3,511 2,542 
Total equity64,483 63,398 63,368 
Dividends paid per common share3.55 3.44 3.34 
The accompanying notes are an integral part of these consolidated financial statements.
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ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended December 31,202320222021
(millions of Canadian dollars)
Operating activities   
Earnings6,058 2,938 6,314 
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization4,613 4,317 3,852 
Deferred income tax expense (Note 24)
1,420 957 1,091 
Unrealized derivative fair value (gain)/loss, net (Note 23)
(1,180)1,280 (173)
Income from equity investments (Note 13)
(1,816)(2,056)(1,600)
Distributions from equity investments1,998 1,827 1,630 
Impairment of long-lived assets419 541 — 
Impairment of goodwill (Note 15)
 2,465 — 
Gain on joint venture merger transaction (Note 13)
 (1,076)— 
(Gain)/loss on dispositions (Note 27)
(15)12 (319)
Other393 37 (73)
Changes in operating assets and liabilities (Note 28)
2,311 (12)(1,466)
Net cash provided by operating activities14,201 11,230 9,256 
Investing activities   
Capital expenditures(4,654)(4,647)(7,818)
Long-term, restricted and other investments(1,276)(1,041)(640)
Distributions from equity investments in excess of cumulative earnings1,151 763 533 
Additions to intangible assets(222)(174)(275)
Acquisitions(954)(828)(3,785)
Proceeds from joint venture merger transaction (Note 13)
 522 — 
Proceeds from dispositions — 1,263 
Net change in affiliate loans(27)135 65 
Other(61)— — 
Net cash used in investing activities(6,043)(5,270)(10,657)
Financing activities
Net change in short-term borrowings(1,596)481 394 
Net change in commercial paper and credit facility draws(8,157)(1,333)2,960 
Debenture and term note issues, net of issue costs15,377 7,547 8,032 
Debenture and term note repayments(4,819)(4,198)(2,264)
Sale of noncontrolling interest in subsidiary (Note 8)
 1,092 — 
Contributions from noncontrolling interests11 13 15 
Distributions to noncontrolling interests(363)(259)(271)
Common shares issued, net of issue costs4,450 
Common shares repurchased(125)(151)— 
Preference share dividends(352)(338)(367)
Common share dividends(7,276)(6,968)(6,766)
Redemption of preference shares (1,003)— 
Redemption of preferred shares held by subsidiary — (415)
Net change in affiliate loan71 — — 
Other(85)(314)(87)
Net cash provided by/(used in) financing activities(2,864)(5,428)1,236 
Effect of translation of foreign denominated cash and cash equivalents and restricted cash(216)55 (5)
Net change in cash and cash equivalents and restricted cash5,078 587 (170)
Cash and cash equivalents and restricted cash at beginning of year907 320 490 
Cash and cash equivalents and restricted cash at end of year5,985 907 320 
Supplementary cash flow information  
Cash paid for income taxes578 495 489 
Cash paid for interest, net of amount capitalized3,380 2,920 2,427 
Property, plant and equipment and intangible assets non-cash accruals813 937 831 
The accompanying notes are an integral part of these consolidated financial statements.
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ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
December 31,20232022
(millions of Canadian dollars; number of shares in millions)
Assets  
Current assets  
Cash and cash equivalents5,901 861 
Restricted cash84 46 
Trade receivables and unbilled revenues4,410 5,616 
Other current assets (Note 9)
2,440 3,255 
Accounts receivable from affiliates85 114 
Inventory (Note 10)
1,479 2,255 
14,399 12,147 
Property, plant and equipment, net (Note 11)
104,641 104,460 
Long-term investments (Note 13)
16,793 15,936 
Restricted long-term investments (Note 23)
717 593 
Deferred amounts and other assets8,041 9,542 
Intangible assets, net (Note 14)
3,537 4,018 
Goodwill (Note 15)
31,848 32,440 
Deferred income taxes (Note 24)
341 472 
Total assets180,317 179,608 
Liabilities and equity  
Current liabilities  
Short-term borrowings (Note 17)
400 1,996 
Trade payables and accrued liabilities4,308 6,172 
Other current liabilities (Note 16)
5,659 5,220 
Accounts payable to affiliates26 105 
Interest payable958 763 
Current portion of long-term debt (Note 17)
6,084 6,045 
17,435 20,301 
Long-term debt (Note 17)
74,715 72,939 
Other long-term liabilities8,653 9,189 
Deferred income taxes (Note 24)
15,031 13,781 
115,834 116,210 
Commitments and contingencies (Note 30)
Equity
Share capital (Note 20)
Preference shares6,818 6,818 
Common shares (2,125 and 2,025 outstanding at December 31, 2023 and 2022, respectively)
69,180 64,760 
Additional paid-in capital268 275 
Deficit(17,115)(15,486)
Accumulated other comprehensive income (Note 22)
2,303 3,520 
Total Enbridge Inc. shareholders’ equity61,454 59,887 
Noncontrolling interests (Note 19)
3,029 3,511 
64,483 63,398 
Total liabilities and equity180,317 179,608 
Variable Interest Entities (VIEs) (Note 12)
The accompanying notes are an integral part of these consolidated financial statements.
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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.Other Current Assets
10.Inventory
11.Property, Plant and Equipment
12.Variable Interest Entities
13.Long-Term Investments
14.Intangible Assets
15.Goodwill
16.Other Current Liabilities
17.Debt
18.Asset Retirement Obligations
19.Noncontrolling Interests
20.Share Capital
21.Stock Option and Stock Unit Plans
22.Components of Accumulated Other Comprehensive Income/(Loss)
23.Risk Management and Financial Instruments
24.Income Taxes
25.Pension and Other Postretirement Benefits
26.Leases
27.Other Income/(Expense)
28.Changes in Operating Assets and Liabilities
29.Related Party Transactions
30.Commitments and Contingencies
31.Guarantees
32.Quarterly Financial Data (Unaudited)
33.Subsequent Event

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1. BUSINESS OVERVIEW

The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge.

Enbridge is a publicly traded energy transportation and distribution company. We conduct our business through five business segments: Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation, and Energy Services. These reporting segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

LIQUIDS PIPELINES
Liquids Pipelines consists of pipelines and terminals in Canada and the United States (US) that transport and export various grades of crude oil and other liquid hydrocarbons, including the Mainline System, Regional Oil Sands System, Gulf Coast and Mid-Continent, and Other. On October 12, 2021, we acquired Moda Midstream Operating, LLC (Moda) (Note 8), which includes the Enbridge Ingleside Energy Center, 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. This segment also includes certain investments in renewable natural gas (RNG) facilities.

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

RENEWABLE POWER GENERATION
Renewable Power Generation consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery, and transmission assets. In North America, assets are primarily located in the provinces of Alberta, Ontario and Québec, and in the states of Colorado, Texas, Indiana, Ohio and West Virginia. We also hold interests in offshore wind facilities in operation, under construction and in active development in the United Kingdom, France and Germany. This segment also includes Tri Global Energy, LLC (TGE) which was acquired on September 27, 2022 (Note 8).

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

ELIMINATIONS AND OTHER
In addition to the segments described above, Eliminations and Other includes operating and administrative costs that are not allocated to business segments, the impact of foreign exchange hedge settlements and the activities of our wholly-owned captive insurance subsidiaries. The principal activity of our captive insurance subsidiaries is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. Eliminations and Other also includes new business development activities and corporate investments.

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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 14); measurement of goodwill (Note 15); fair value of asset retirement obligations (ARO) (Note 18); valuation of stock-based compensation (Note 21); fair value of financial instruments (Note 23); provisions for income taxes (Note 24); assumptions used to measure retirement benefits and OPEB (Note 25); 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 the accounts of our subsidiaries and VIEs for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity's operations through voting rights or do not substantively participate in the gains and losses of the entity. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses, or the right to receive benefits from, the VIE that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We assess the primary beneficiary determination for a VIE on an ongoing basis if there are changes in the facts and circumstances related to a VIE. If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses.

All 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.
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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 BC Energy Regulator, the Ontario Energy Board (OEB) and the Québec Régie de l’énergie. 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, amounts collected from customers in advance of costs being incurred, or 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 regulator. If there are changes in our assessment of the probability of recovery for a regulatory asset, we reduce its carrying amount to the balance that we expect to recover from customers in future periods through rates. If a regulator later excludes from allowable costs all or a part of costs that were capitalized as a regulatory asset, we reduce the carrying amount of the asset by the excluded amounts. 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.

During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements. We do not expect to renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline is no longer subject to rate-regulated accounting. As a result, the related regulatory liabilities, regulatory tax assets and associated regulatory deferred tax liabilities were derecognized. We believe that the recovery of our remaining regulatory assets as at December 31, 2023 is probable over the periods described in Note 7 - Regulatory Matters.

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 regulatory requirements under the LMCI. The funds collected are held in trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues in the Consolidated Statements of Earnings and Restricted long-term investments in the Consolidated Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense in the Consolidated Statements of Earnings and Other long-term liabilities in the Consolidated Statements of Financial Position.

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

110


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.

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 and throughout the contract duration. Certain revenues from our liquids and natural gas pipeline businesses are recognized under the terms of committed delivery contracts, rather than the cash tolls received.

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

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

For the years ended December 31, 2023, 2022 and 2021, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $210 million, $238 million and $127 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 we are acting as the principal in the transactions.

111


No non-affiliated customer exceeded 10.0% of our third-party revenues for the years ended December 31, 2023 and 2022. Our largest non-affiliated customer accounted for approximately 13.5% of our third-party revenues for the year ended December 31, 2021.

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 revenues, Commodity costs, Operating and administrative expense, Other income/(expense) and Interest expense.

Derivatives in Qualifying Hedging Relationships
We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires us to document the hedging relationship and test the hedging item's effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION
Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated to the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting from the translation of monetary assets and liabilities are included in earnings in the period in which they arise.
Gains and losses arising from the translation of foreign operations' functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect as at the balance sheet date, while revenues and expenses are translated using monthly average exchange rates.

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

RESTRICTED CASH
Cash and cash equivalents that are restricted as to withdrawal or usage for the purposes of the CER's LMCI or in accordance with specific commercial and debt arrangements are presented as Restricted cash in the Consolidated Statements of Financial Position.

LOANS AND RECEIVABLES
Long-term notes receivable from affiliates are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Trade receivables and unbilled revenues 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. Trade receivables and unbilled revenues are presented net of allowance for expected credit losses of $100 million and $92 million as at December 31, 2023 and 2022, respectively.

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

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INVENTORY
Inventory is comprised of natural gas held in storage by Enbridge Gas, crude oil and natural gas held primarily by businesses in our 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.

Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting 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.

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. The lease term may include periods associated with options to extend or terminate the lease if it is reasonably certain the options will be exercised.

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 for certain regulated entities; actual cost of removal of previously retired or decommissioned plant assets; the difference between the actual cost and approved cost of natural gas reflected in rates; and actuarial gains and losses arising from defined benefit pension plans for Enbridge Gas.

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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. Our reporting units are Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation. The Renewable Power Generation reporting unit had goodwill beginning in the third quarter of 2022.

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

The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit's carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using a discounted cash flow technique. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, expected future capital expenditures and working capital levels, as well as terminal value growth rates for the Liquids Pipelines, Gas Transmission, and Renewable Power Generation reporting units, and projected regulatory rate base and rate base multiple for the Gas Distribution and Storage reporting unit.

The 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.

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On April 1, 2023, we performed our annual goodwill impairment assessment which consisted of a qualitative assessment for the Liquids Pipelines, Gas Transmission, Gas Distribution and Storage, and Renewable Power Generation reporting units and did not identify impairment indicators. Due to an impairment recorded in 2022 for the Gas Transmission reporting unit and the OEB decision on Phase 1 for Enbridge Gas, we performed a quantitative assessment for the Gas Transmission and Gas Distribution and Storage reporting units as at December 1, 2023, which did not result in the recognition of an impairment charge for either reporting unit. Also, we did not identify any indicators of goodwill impairment during the remainder of 2023.

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 investment.

ASSET RETIREMENT OBLIGATIONS
ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Other current liabilities 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 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, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements.

PENSION AND OTHER POSTRETIREMENT BENEFITS
We sponsor defined benefit and defined contribution pension plans, as well as defined benefit OPEB plans.

Obligations and net periodic benefit costs for defined benefit pension and OPEB plans are estimated using the projected unit credit method, which is based on years of service, as well as our best estimates of actuarial assumptions such as discount rates, future salary levels, other cost escalations, employees' retirement ages, and mortality.

We determine discount rates using market yields of high-quality corporate bonds with maturities that approximate the estimated timing of future benefit payments.

Plan assets are measured at fair value. The expected return on plan assets is determined using the long-term target asset mixes in our investment policies and long-term market expectations.

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Actuarial gains and losses arise from the difference between the actual and expected return on plan assets, and changes in actuarial assumptions such as discount rates. Periodic net actuarial gains and losses and prior service costs are accumulated and presented as follows in the Consolidated Statements of Financial Position:

as a component of AOCI, for our non-utilities' defined benefit pension plans and all defined benefit OPEB plans; and
as a component of Deferred amounts and other assets and/or Other long-term liabilities, for our utilities' defined benefit pension plans, to the extent that the net actuarial gains and losses and prior service costs have been permitted or are expected to be permitted by the regulators, to be recovered through future rates.

Net periodic benefit cost is recognized in earnings and includes:

current service cost;
interest cost;
expected return on plan assets;
amortization of prior service costs over the expected average remaining service life of the plans' active employee group; and
amortization of net actuarial gains and losses in excess of 10% of the greater of the benefit obligation or the fair value of plan assets over the expected average remaining service life of the plans' active employee group.

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

For defined contribution plans, our contributions are expensed when the contribution occurs.

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

Performance stock units (PSU) and certain RSUs are cash-settled awards for which the related liability is remeasured each reporting period. These PSUs vest at the completion of a three-year term and RSUs vest one-third annually from the grant date. During the vesting term, compensation expense is recorded based on the number of units outstanding and the current market price of Enbridge's common shares with an offset to Other current liabilities or Other long-term liabilities. The value of the PSUs is also dependent on our performance relative to performance targets set out under the plan. We also award share-settled RSUs to certain senior management employees which vest at the completion of a three-year term. Beginning in 2023, share-settled units were granted to other employees, which vest one-third annually from the grant date. During the vesting term, compensation expense is recorded based on the number of units granted and the market price of Enbridge's common shares on the day immediately preceding the grant date, with an offset to Additional paid-in capital. There is no associated liability recorded for share-settled awards.

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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 Other current liabilities and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in the Consolidated Statements of Financial Position.

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

3.  CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES
There were no changes in accounting policies during the year ended December 31, 2023.

FUTURE ACCOUNTING POLICY CHANGES
Segment Reporting
Accounting Standards Update (ASU) 2023-07 was issued in November 2023 to improve reportable segment disclosure requirements primarily through enhanced disclosures about significant segment expenses and to require in interim period financial statements all disclosures about a reportable segment's profit or loss and assets that are currently required annually. The new ASU requires entities to disclose the title and position of the individual or the name of the group or committee identified as the chief operating decision-maker (CODM) of each segment. ASU 2023-07 is effective January 1, 2024, with interim period disclosure requirements effective after January 1, 2025 and should be applied retrospectively to all prior periods presented in the financial statements. We are currently assessing the impact of the new standard on our consolidated financial statements.

Income Tax Disclosures
ASU 2023-09 was issued in December 2023 to improve income tax disclosures by requiring specified categories in the annual rate reconciliation that meet quantitative thresholds and further disaggregation on income taxes paid by jurisdiction. ASU 2023-09 is effective January 1, 2025 and should be applied prospectively, with retrospective application being permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.


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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, 2023
(millions of Canadian dollars)       
Transportation revenue11,875 5,302 814    17,991 
Storage and other revenue257 461 355    1,073 
Gas distribution revenue  4,859    4,859 
Electricity and transmission revenue   259   259 
Commodity sales 17     17 
Total revenue from contracts with customers12,132 5,780 6,028 259   24,199 
Commodity sales    18,964  18,964 
Other revenue1,2
257 72 (58)215   486 
Intersegment revenue474 2 6 3 25 (510) 
Total revenue12,863 5,854 5,976 477 18,989 (510)43,649 

Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
Year ended December 31, 2022
(millions of Canadian dollars)       
Transportation revenue11,283 5,012 782 — — — 17,077 
Storage and other revenue235 350 308 — — — 893 
Gas gathering and processing revenue— 22 — — — — 22 
Gas distribution revenue— — 5,643 — — — 5,643 
Electricity and transmission revenue   281 — — 281 
Total revenue from contracts with customers11,518 5,384 6,733 281 — — 23,916 
Commodity sales— — — — 29,150 — 29,150 
Other revenue1,2
(81)39 (20)305 — — 243 
Intersegment revenue615 16 (4)25 (655)— 
Total revenue12,052 5,426 6,729 582 29,175 (655)53,309 

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 19 (1)44 (630)— 
Total revenue10,581 4,711 4,980 512 26,917 (630)47,071 
1Includes realized and unrealized gains and losses from our hedging program which for the year ended December 31, 2023 were a net of $97 million loss (2022 - $431 million loss; 2021 - $59 million gain).
2Includes revenues from lease contracts. Refer to Note 26 - Leases.
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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, 20232,802 400 2,591 
Balance as at December 31, 20223,183 230 2,241 

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

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

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the year ended December 31, 2023 included in contract liabilities at the beginning of the year is $246 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2023, were $632 million.

Performance Obligations
SegmentNature of Performance Obligation
Liquids Pipelines
Transportation and storage of crude oil and natural gas liquids (NGL)
Gas Transmission and Midstream
Transportation, storage, gathering, compression and treating of natural gas
Transportation of NGL
Sale of crude oil, natural gas and NGL
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 during the year ended December 31, 2023 from performance obligations satisfied in previous periods.

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

Certain contracts in our US offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period that is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs are recorded as contract liabilities. The FMPs are not considered to be a financing arrangement as payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives.
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Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is $59.1 billion, of which $7.5 billion is expected to be recognized during the year ending December 31, 2024.

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

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

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

During the first six months of 2023, revenue for the Canadian Mainline was recognized in accordance with the terms of the Competitive Toll Settlement (CTS), which expired on June 30, 2021. The tolls in place on June 30, 2021 continued on an interim basis until July 1, 2023 when revised interim tolls took effect. Until a new commercial arrangement is approved, the tolls 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, 2023 is considered variable consideration.
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Recognition and Measurement of Revenue
Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationConsolidated
Year ended December 31, 2023
(millions of Canadian dollars)    
Revenue from products transferred at a point in time 17 138  155 
Revenue from products and services transferred over time1
12,132 5,763 5,890 259 24,044 
Total revenue from contracts with customers12,132 5,780 6,028 259 24,199 

Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationConsolidated
Year ended December 31, 2022
(millions of Canadian dollars)    
Revenue from products transferred at a point in time— — 127 — 127 
Revenue from products and services transferred over time1
11,518 5,384 6,606 281 23,789 
Total revenue from contracts with customers11,518 5,384 6,733 281 23,916 

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 
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
Year ended December 31, 2023Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
(millions of Canadian dollars)       
Operating revenues (Note 4)
12,863 5,854 5,976 477 18,989 (510)43,649 
Commodity and gas distribution costs (15)(2,871)(20)(18,975)515 (21,366)
Operating and administrative(4,629)(2,380)(1,285)(261)(52)7 (8,600)
Impairment of long-lived assets1
145  (281)(283)  (419)
Income/(loss) from equity investments (Note 13)
1,007 688 2 140  (21)1,816 
Other income (Note 27)
113 117 51 96 1 846 1,224 
Earnings/(loss) before interest, income taxes and depreciation and amortization9,499 4,264 1,592 149 (37)837 16,304 
Depreciation and amortization(4,613)
Interest expense (Note 17)
      (3,812)
Income tax expense (Note 24)
      (1,821)
Earnings      6,058 
Capital expenditures2
1,158 1,944 1,451 100  55 4,708 
Total property, plant and equipment, net (Note 11)
51,851 31,016 18,766 2,706 4 298 104,641 

Year ended December 31, 2022Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
(millions of Canadian dollars)       
Operating revenues (Note 4)
12,052 5,426 6,729 582 29,175 (655)53,309 
Commodity and gas distribution costs— — (3,693)(16)(29,525)645 (32,589)
Operating and administrative(4,287)(2,254)(1,289)(255)(49)(85)(8,219)
Impairment of long-lived assets(245)— — (235)(13)(48)(541)
Impairment of goodwill (Note 15)
— (2,465)— — — — (2,465)
Income/(loss) from equity investments (Note 13)
785 1,133 141 — (4)2,056 
Gain on joint venture merger transaction (Note 13)
— 1,076 — — — — 1,076 
Other income/(expense) (Note 27)
59 210 79 45 (5)(977)(589)
Earnings/(loss) before interest, income taxes and depreciation and amortization8,364 3,126 1,827 262 (417)(1,124)12,038 
Depreciation and amortization(4,317)
Interest expense (Note 17)
      (3,179)
Income tax expense (Note 24)
      (1,604)
Earnings      2,938 
Capital expenditures2
1,418 1,690 1,499 50 — 33 4,690 
Total property, plant and equipment, net (Note 11)
53,567 29,666 17,857 3,082 282 104,460 

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Year ended December 31, 2021Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
(millions of Canadian dollars)       
Operating revenues (Note 4)
10,581 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 investments (Note 13)
759 702 42 101 — (4)1,600 
Other income/(expense) (Note 27)
13 135 385 75 (8)379 979 
Earnings/(loss) before interest, income taxes and depreciation and amortization7,897 3,671 2,117 508 (313)356 14,236 
Depreciation and amortization(3,852)
Interest expense (Note 17)
(2,655)
Income tax expense (Note 24)
(1,415)
Earnings6,314 
Capital expenditures2
4,051 2,420 1,343 16 54 7,885 
Total property, plant and equipment, net52,530 27,028 16,904 3,315 23 267 100,067 
1The Liquids Pipelines segment includes the impact of a gain resulting from the derecognition of a net regulatory liability due to the discontinuance of regulatory accounting for our Southern Lights Pipeline (Note 7).
2Includes equity component of AFUDC.

The measurement basis for preparation of segmented information is consistent with our significant accounting policies (Note 2).

GEOGRAPHIC INFORMATION
Revenues1
Year ended December 31,202320222021
(millions of Canadian dollars)   
Canada23,781 27,498 20,474 
US19,868 25,811 26,597 
 43,649 53,309 47,071 
1Revenues are based on the country of origin of the product or service sold.

Property, Plant and Equipment1
December 31,20232022
(millions of Canadian dollars)  
Canada48,570 47,602 
US56,071 56,858 
 104,641 104,460 
1Amounts are based on the location where the assets are held.

Change in Reportable Segments
Effective January 1, 2024, to better align how the CODM reviews operating performance and resource allocation across operating segments, we transferred our Canadian and US crude oil businesses from the Energy Services segment to the Liquids Pipelines segment. The Energy Services segment will cease to exist and the remainder of the business will be reported in the Eliminations and Other segment. Beginning in the first quarter of 2024, prior period comparable results for segmented information will be recast to reflect the change in reportable segments. This segment reporting change will have no impact on our consolidated results.
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6.  EARNINGS PER COMMON SHARE

BASIC
Earnings per common share is calculated by dividing earnings attributable to common shareholders by 2,020 million, the weighted average number of Enbridgecommon shares outstanding asoutstanding. On December 30, 2021, we closed the sale of December 31, 2020. For purposes of the 2020 STIP award determinations as described on page 26, DCF was converted to DCF per share by taking DCF of C$9,473 million and dividing by 2,020 million, theour minority ownership in Noverco. The weighted average number of Enbridgecommon shares outstanding was reduced by our pro-rata weighted average interest in our own common shares of approximately 2 million as at December 31, 2021 resulting from our reciprocal investment in Noverco.

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

Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:

December 31,202320222021
(number of shares in millions)   
Weighted average shares outstanding2,056 2,025 2,023 
Effect of dilutive options and RSUs2 
Diluted weighted average shares outstanding2,058 2,029 2,025 

For the years ended December 31, 2023, 2022 and 2021, 19.3 million, 10.4 million and 18.6 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $54.42, $56.49 and $52.89, respectively, were excluded from the diluted earnings per common share calculation.

7. REGULATORY MATTERS

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

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

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LIQUIDS PIPELINES
Canadian Mainline
Canadian Mainline includes the Canadian portion of our Mainline system. The 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 at which point the tolls in place became interim. Enbridge has reached an agreement on a new negotiated settlement, the Mainline Tolling Settlement (MTS), for tolls on its Mainline System. The settlement is subject to regulatory approval and the term is seven and a half years through the end of 2028, with revised interim tolls effective on July 1, 2023. The MTS continues with the previous CTS framework with a Canadian Local Toll for all volumes shipped on the Canadian Mainline and an International Joint Tariff for all volumes shipped from western Canadian receipt points to delivery points on our Lakehead System. We have recognized a regulatory asset of $1.9 billion as at December 31, 2023 (2022 - $2.1 billion) to offset deferred income taxes, as a CER rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the MTS. During the year ended December 31, 2023, we wrote off $160 million related to regulatory tax assets and $40 million of regulatory deferred tax liabilities that are no longer probable to be flowed through future tolls.

Southern Lights Pipeline
The US and Canadian portions of the Southern Lights Pipeline are regulated by the FERC and CER, respectively. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost-of-service toll methodology. Toll adjustments are filed annually with the regulators and provide for the recovery of allowable operating and debt financing costs, plus a pre-determined after-tax return on equity (ROE) of 10%. During the fourth quarter of 2023, Southern Lights Pipeline completed an open season to negotiate new transportation service agreements effective 2025. We do not expect to renew the agreements under a cost-of-service toll methodology, therefore Southern Lights Pipeline is no longer subject to rate-regulated accounting. As a result, $151 million of net regulatory liabilities, $92 million of regulatory tax assets and $23 million of regulatory deferred tax liabilities were derecognized in the year.

GAS TRANSMISSION AND MIDSTREAM
British Columbia Pipeline and Maritimes & Northeast Canada
British Columbia (BC) Pipeline and Maritimes & Northeast Canada (M&N Canada) are regulated by the CER. Rates are approved by the CER through negotiated toll settlement agreements based on cost-of-service. Both our BC Pipeline and M&N Canada systems currently operate under the terms of their respective 2022 - 2026 and 2022 - 2023 settlement agreements, which stipulate an allowable ROE and the continuation and establishment of certain deferral and variance accounts. The toll settlement agreement for M&N Canada expired in December 2023. M&N Canada reached a toll settlement with shippers for the effective period from January 1, 2024 to December 31, 2025. On November 28, 2023, M&N Canada filed the 2024 - 2025 toll settlement agreement with the CER for review and approval. A CER decision is expected in the first quarter of 2024.

US Gas Transmission
Most of our US gas transmission and storage services are regulated by the FERC and may also be subject to the jurisdiction of various other federal, state and local agencies. The FERC regulates natural gas transmission in US interstate commerce including the establishment of rates for services, while rates for intrastate commerce and/or gathering services are regulated by the state gas commissions. Cost-of-service is the basis for the calculation of regulated tariff rates, although the FERC also allows the use of negotiated and discounted rates within contracts with shippers that may result in a rate that is above or below the FERC-regulated recourse rate for that service.
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GAS DISTRIBUTION AND STORAGE
Enbridge Gas
Enbridge Gas' distribution rates, commencing in 2019, were set under a five-year Incentive Regulation (IR) framework using a price cap mechanism ending December 31, 2023. 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.

On December 21, 2023, we received a decision from the OEB on Phase 1 of our 2024 - 2028 Incentive Regulation rate setting framework (Phase 1 Decision). The Phase 1 Decision established new interim rates effective January 1, 2024. In addition, the Phase 1 Decision resulted in the following items not approved for future recovery, and the subsequent impairments recognized for the year ended December 31, 2023:

a portion of undepreciated capital projects in Property, plant and equipment, net and Intangible assets, net were removed from 2024 rate base of $41 million;
undepreciated integration capital costs in Intangible assets, net were removed from 2024 rate base of $84 million;
pre-2017 Union Gas related pension balances in Deferred amounts and other assets of $156 million.


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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 31,20232022Recovery/Refund
Period Ends
(millions of Canadian dollars)
Current regulatory assets
   Purchase gas variance15 190 2024
   Under-recovery of fuel costs75 109 2024
   Other current regulatory assets380 305 2024
Total current regulatory assets1 (Note 9)
470 604 
Long-term regulatory assets
   Deferred income taxes2
4,456 4,473 Various
   Long-term debt3
348 378 2032-2046
Negative salvage4
180 265 Various
   Purchase gas variance 244 2024
   Accounting policy changes5
 219 2024
   Pension plan receivable6
1 40 Various
   Other long-term regulatory assets252 244 Various
Total long-term regulatory assets1
5,237 5,863 
Total regulatory assets5,707 6,467 
Current regulatory liabilities
   Purchase gas variance31 — 2024
   Other current regulatory liabilities276 167 2024
Total current regulatory liabilities7
307 167 
Long-term regulatory liabilities
   Future removal and site restoration reserves8
1,693 1,615 Various
   Regulatory liability related to US income taxes9
854 918 2050-2072
   Pipeline future abandonment costs (Note 23)
745 610 Various
   Pension plan payable6
143 231 Various
   Other long-term regulatory liabilities86 250 Various
Total long-term regulatory liabilities7
3,521 3,624 
Total regulatory liabilities3,828 3,791 
1Current regulatory assets are included in Other current assets, while long-term regulatory assets are included in Deferred amounts and other assets.
2Represents 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. The balance as at December 31, 2023 is net of regulatory deferred tax write-offs.
3Represents 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.
4The 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.
5In 2022, this deferral primarily consisted of unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited, relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and recovered in rates, as previously approved by the OEB. The Phase 1 Decision disallowed recovery of the remaining balance related to pre-2017 pension amounts and was impaired with a nil balance as at December 31, 2023. The residual balance in this account pertains to the impact of other accounting changes during the deferred rebasing period and were approved for disposition in 2024 in the Phase 1 Decision and subsequently transferred to Other current regulatory assets as at December 31, 2023.
6Represents 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.
7Current regulatory liabilities are included in Other current liabilities, while long-term regulatory liabilities are included in Other long-term liabilities.
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8Future 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.
9The regulatory liability related to US income taxes resulted from the US tax reform legislation dated December 22, 2017. These balances will be refunded to customers in accordance with the respective rate settlements approved by the FERC.

8.  ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS
Aitken Creek Gas Storage
On November 1, 2023, through a wholly-owned Canadian subsidiary, we acquired a 93.8% interest in Aitken Creek Gas Storage Facility and a 100% interest in Aitken Creek North Gas Storage Facility (collectively, Aitken Creek), located in BC, Canada, for $400 million, subject to other customary closing adjustments (the Aitken Creek Acquisition). Aitken Creek is the only underground natural gas storage facility in BC and connects to all major natural gas pipelines in western Canada. The Aitken Creek Acquisition enables us to continue to meet regional energy needs and to support increasing demand for liquefied natural gas (LNG) exports.

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

The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Aitken Creek:
November 1, 2023
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets (a)105
Property, plant and equipment (b)466
Current liabilities20
Long-term liabilities (c)130
Goodwill (d)46
Purchase price:
Cash397
Additional consideration (e)70
467

a) Current assets consist primarily of inventory which is short-term in nature and represents natural gas held in storage. Fair value was determined using the market price of natural gas at the date of acquisition.

b) Aitken Creek's property, plant and equipment constitutes an integrated system of cavern storage facilities, associated header pipeline, and land and right-of-ways. The depreciated replacement cost approach was adopted as the primary valuation methodology to determine the fair value of property, plant and equipment, excluding the reservoir storage asset. 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.

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Fair value of the reservoir storage asset was determined using a residual approach whereby the adjusted purchase price was allocated to the fair value of the net tangible assets, excluding the reservoir storage asset, with the remaining value allocated to the reservoir storage asset. The income approach was also utilized to corroborate that the cash flows attributable to the reservoir storage asset support the residual value.

c) Long-term liabilities consist primarily of a deferred income tax liability arising from temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes at the date of acquisition.

d) Goodwill is primarily attributable to the recognition of a deferred income tax liability. The goodwill balance recognized has been assigned to our Gas Transmission and Midstream segment and is not tax deductible.

e) The $70 million of additional consideration recognized in the purchase price represents the fair value of derivative contracts and working gas as at March 31, 2023.

Upon completion of the Aitken Creek Acquisition, we began consolidating Aitken Creek. For the period beginning November 1, 2023 through to December 31, 2023, operating revenues and earnings attributable to common shareholders generated by Aitken Creek were immaterial. The impact to our supplemental pro forma consolidated operating revenues and earnings attributable to common shareholders for the years ended December 31, 2023 and 2022, as if the Aitken Creek Acquisition had been completed on January 1, 2022, was also immaterial.

Acquisitions of US Gas Utilities
On September 5, 2023, we announced that Enbridge had entered into three separate definitive agreements with Dominion Energy, Inc. to acquire The East Ohio Gas Company, Questar Gas Company and its related Wexpro companies, and Public Service Company of North Carolina for an aggregate purchase price of $19.1 billion (US$14.0 billion), comprised of $12.8 billion (US$9.4 billion) of cash consideration and $6.3 billion (US$4.6 billion) of assumed debt, subject to customary closing adjustments (together, the Acquisitions). The Acquisitions are expected to close in 2024, subject to the satisfaction of customary closing conditions including the receipt of certain regulatory approvals, which are not cross-conditional.

On September 8, 2023, we closed a public offering of 102,913,500 common shares at a price of $44.70 per share for gross proceeds of $4.6 billion which is intended to finance a portion of the aggregate cash consideration payable for the Acquisitions.

We closed two offerings in September 2023 and four offerings in November 2023 for aggregate principal amounts of US$5.5 billion and $1.0 billion. The proceeds from the September 2023 offerings and a portion of the November 2023 offerings are intended to finance a portion of the aggregate cash consideration payable for the Acquisitions. Refer to Note 17 - Debt for further details on the debt issuances and credit facility obtained to support the Acquisitions.

Tres Palacios Holdings LLC
On April 3, 2023, we acquired Tres Palacios Holdings LLC (Tres Palacios) for $451 million (US$335 million) of cash. Tres Palacios is a natural gas storage facility located in the US Gulf Coast and its infrastructure serves Texas gas-fired power generation and LNG exports, as well as Mexico pipeline exports.

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We allocated assets with a fair value of $790 million (US$588 million) to Property, plant and equipment, net, of which $254 million (US$189 million) relates to storage cavern right-of-use assets, and recorded the related lease liabilities of $7 million (US$5 million) and $248 million (US$184 million) to Current portion of long-term debt and Long-term debt, respectively, in the Consolidated Statements of Financial Position. The acquired assets are included in our Gas Transmission and Midstream segment.

Tri Global Energy, LLC
On September 27, 2022, through a wholly-owned US subsidiary, we acquired all of the outstanding common units in TGE for cash consideration of $295 million (US$215 million) plus potential contingent payments of up to $72 million (US$53 million) dependent on the achievement of performance milestones by TGE (the TGE Acquisition).TGE is an onshore renewable project developer in the US with a development portfolio of wind and solar projects. The TGE Acquisition enhances Enbridge's renewable power platform and accelerates our North American growth strategy.

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

The following table summarizes the estimated fair values that were assigned to the net assets of TGE:
September 27, 2022
(millions of Canadian dollars)
Fair value of net assets acquired:
Current assets
Property, plant and equipment
Long-term investments
Intangible assets (a)117 
Long-term assets
Current liabilities61 
Long-term debt18 
Long-term liabilities (b)105 
Goodwill (c)392 
Purchase price:
Cash295 
Contingent consideration (d)49 
344 

a) Intangible assets consist of compensation expected to be earned by TGE on existing development contracts once certain project development milestones are met. Fair value was determined using a discounted cash flow method which is an income-based approach to valuation that estimates the present value of future projected benefits from the contracts. The intangible assets will be amortized on a straight-line basis over an expected useful life of three and a half years.

b) Long-term liabilities consist primarily of obligations payable to third parties which are contingent on milestones being met for certain projects. Fair value represents the present value of the future cash flow payments at the date of the TGE Acquisition.

c) Goodwill is primarily attributable to expected future returns from new opportunities to develop wind and solar projects, as well as enhanced scale and operational diversity of our renewable projects portfolio. The goodwill balance recognized has been assigned to our Renewable Power Generation segment and is tax deductible over 15 years.

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d) We agreed to pay additional contingent consideration of up to US$53 million to TGE's former
common unit holders if performance milestones are met on certain projects. The US$36 million of contingent consideration recognized in the purchase price represents the fair value of contingent
consideration at the date of acquisition. The fair value was determined using an income-based approach.

Upon completion of the TGE Acquisition, we began consolidating TGE. For the period beginning September 27, 2022 through to December 31, 2022, operating revenues and earnings attributable to common shareholders generated by TGE were immaterial. The impact to our supplemental pro forma consolidated operating revenues and earnings attributable to common shareholders for the years ended December 31, 2022 and 2021, as if the TGE Acquisition had been completed on January 1, 2021, was also immaterial.

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

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

The following table summarizes the estimated fair values that were assigned to the net assets of Moda:
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.

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b) Long-term investments represent Moda's 20% equity interest in Cactus II Pipeline LLC (Cactus II). The fair value of Cactus II was determined using the discounted cash flow method. The discounted cash flow method is an income-based approach to valuation which estimates the present value of future projected benefits from the investment.

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

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

e) We agreed to pay additional contingent consideration of up to US$150 million to Moda's former membership interest holders if Moda's monthly volumes of crude oil loaded onto a vessel equal or exceed specified throughput levels. These performance requirements terminate the earlier of December 31, 2020.2023 or the date the final contingent payment is made. The US$150 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition and was fully settled as at December 31, 2022.

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

Upon completion of the Moda Acquisition, we began consolidating Moda. For purposesthe 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 year ended December 31, 2021, including the results of 2018 PSU payout determinationsoperations for Moda as describedif the Moda Acquisition had been completed on pageJanuary 1, 2020, are as follows:

Year ended December 31,2021
(unaudited; millions of Canadian dollars)
Operating revenues47,339 
Earnings attributable to common shareholders1,2
5,771 
1Acquisition-related expenses of $21 million (after-tax $16 million) were excluded from earnings attributable to common shareholders for the year ended December 31, DCF2021.
2Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets of $193 million (after-tax of $145 million) for the year ended December 31, 2021.

DISPOSITIONS
Athabasca Regional Oil Sands System
On October 5, 2022, we closed the sale of an 11.6% non-operating interest in seven pipelines in the Athabasca region of northern Alberta from our Regional Oil Sands System to Athabasca Indigenous Investments Limited Partnership (Aii), an entity representing 23 First Nation and Métis communities, for total consideration of approximately $1.1 billion, less customary closing adjustments. No gain or loss was convertedrecognized on the sale and a noncontrolling interest was recorded in our Consolidated Statements of Financial Position as at December 31, 2022 to DCF perreflect the interest held by Aii (Note 19).

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Subsequent to the sale, we maintained an 88.4% controlling interest in these assets, which are a component of our Liquids Pipelines segment, and continue to manage, operate and provide administrative services to them.

9.  OTHER CURRENT ASSETS
December 31,20232022
(millions of Canadian dollars)
Derivative assets (Note 23)
623 1,015 
Regulatory assets (Note 7)
470 604 
Gas imbalances209 461 
Income taxes receivable347 323 
Other791 852 
 2,440 3,255 

10.  INVENTORY
December 31,20232022
(millions of Canadian dollars)  
Natural gas938 1,491 
Crude oil413 652 
Other128 112 
 1,479 2,255 

11.  PROPERTY, PLANT AND EQUIPMENT
 Weighted Average  
December 31,Depreciation Rate20232022
(millions of Canadian dollars)   
Pipelines2.9 %66,698 66,528 
Facilities and equipment3.1 %37,634 37,028 
Land and right-of-way1
2.3 %3,600 3,637 
Gas mains, services and other2.6 %15,346 14,491 
Storage2.5 %4,929 3,477 
Wind turbines, solar panels and other4.1 %4,511 4,912 
Other10.1 %1,652 1,611 
Under construction— %2,829 2,316 
Total property, plant and equipment 137,199 134,000 
Total accumulated depreciation(32,558)(29,540)
Property, plant and equipment, net 104,641 104,460 
1The measurement of weighted average depreciation rate excludes non-depreciable assets.

Depreciation expense for the years ended December 31, 2023, 2022 and 2021 was $4.0 billion, $3.8 billion and $3.5 billion, respectively.

IMPAIRMENT
Chapman Ranch Wind Farm
Chapman Ranch Wind Farm (Chapman Ranch) is experiencing financial challenges associated with the original equipment integrity. As a result, we have recognized an impairment loss of $251 million for the year ended December 31, 2023, which is included in Impairment of long-lived assets in the Consolidated Statements of Earnings and is part of our Renewable Power Generation segment.
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Magic Valley Wind Farm
In 2022, Magic Valley Wind Farm (Magic Valley) had commercial challenges caused by electricity transmission congestion and a negative price differential arising from higher transmission costs resulting in a lower electricity sale price. As a result, we recognized an impairment loss of $227 million for the year ended December 31, 2022, which is included in Impairment of long-lived assets in the Consolidated Statements of Earnings and is part of our Renewable Power Generation segment.

Bakken Pipeline System
For the year ended December 31, 2022, we recognized an impairment loss of $183 million on the US and Canadian components of the interstate pipeline transportation system within the North Dakota System of our Bakken Pipeline System in connection with the expiration of certain long-term take-or-pay contracts in 2023. This loss is included in Impairment of long-lived assets in the Consolidated Statements of Earnings and is part of our Liquids Pipelines segment.

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

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.

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The following table includes assets to be used to settle liabilities of our consolidated VIEs. The creditors of the liabilities of our consolidated VIEs do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.

December 31,20232022
(millions of Canadian dollars)  
Assets  
Cash and cash equivalents442 426 
Restricted cash9 12 
Trade receivables and unbilled revenue144 185 
Other current assets8 14 
Accounts receivable from affiliates5 23 
Inventory11 12 
 619 672 
Property, plant and equipment, net7,105 7,707 
Long-term investments14 14 
Restricted long-term investments106 98 
Deferred amounts and other assets148 158 
Intangible assets, net84 102 
 8,076 8,751 
Liabilities  
Trade payables and accrued liabilities83 99 
Other current liabilities145 152 
Accounts payable to affiliates4 21 
 232 272 
Long-term debt1 — 
Other long-term liabilities971 859 
Deferred income taxes5 
 1,209 1,136 
6,867 7,615 
We do not have obligations to provide additional financial support to any of our consolidated VIEs.

UNCONSOLIDATED VARIABLE INTEREST ENTITIES
We currently hold interests in several non-consolidated VIEs where we are not the primary beneficiary as we do not have the power to direct the activities of the VIEs that most significantly impact their economic performance. These interests include investments in limited partnerships that are assessed to be VIEs due to the limited partners not having substantive kick-out rights or participating rights. The power to direct the activities of a majority of these non-consolidated limited partnership VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee that makes significant decisions for the VIE, and none of the partners may make significant decisions unilaterally.

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The carrying amount of these VIEs and our estimated maximum exposure to loss as at December 31, 2023 and 2022 are presented below:
Carrying
Amount of
Maximum
Exposure to
December 31, 2023the VIELoss
(millions of Canadian dollars)  
Aux Sable Liquid Products L.P.1
105 130 
Rampion Offshore Wind Limited2
391 452 
Vector Pipeline L.P.3
191 320 
Woodfibre LNG Limited Partnership4
778 2,854 
Fox Squirrel Solar LLC5
312 661 
Other4
132 230 
 1,909 4,647 

Carrying
Amount of
Maximum
Exposure to
December 31, 2022the VIELoss
(millions of Canadian dollars)  
Aux Sable Liquid Products L.P.1
91 117 
EIH S.á r.l.6
37 637 
Rampion Offshore Wind Limited2
413 468 
Vector Pipeline L.P.3
195 325 
Woodfibre LNG Limited Partnership4
635 2,476 
Other4
245 443 
1,616 4,466 
1As at December 31, 2023 and 2022, the maximum exposure to loss includes a guarantee by us for our respective share of the VIE's borrowing on a bank credit facility.
2As at December 31, 2023 and 2022, 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 taking DCFthe VIE.
3As at December 31, 2023 and 2022, the maximum exposure to loss includes the carrying value of C$9,848outstanding affiliate loans receivable for $24 million and dividing$25 million held by 2,020us as at December 31, 2023 and 2022, respectively, and an outstanding credit facility for $105 million as at December 31, 2023 and 2022.
4As at December 31, 2023 and 2022, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE.
5In November 2023, Enbridge acquired a 50% interest in Fox Squirrel JV, LLC (Fox Squirrel Solar LLC). Refer to Note 13 - Long-Term Investments. Fox Squirrel Solar LLC is a VIE due to its lack of sufficient equity at risk to finance its activities. Enbridge does not hold decision-making rights to direct Fox Squirrel Solar LLC's activities that most significantly impacts its economic performance. As at December 31, 2023, 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.
6As at December 31, 2023, EIH S.á r.l no longer met the requirements of a VIE as a result of a VIE reconsideration event. As at December 31, 2022, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the three French offshore wind projects for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $56 million.

We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2023 and 2022.

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13.  LONG-TERM INVESTMENTS
 Ownership  
December 31,Interest20232022
(millions of Canadian dollars)   
EQUITY INVESTMENTS   
Liquids Pipelines   
MarEn Bakken Company LLC1
75.0 %1,819 1,968 
DCP Midstream, LLC (Class B Units)2
90.0 %1,486 1,394 
Seaway Crude Holdings LLC50.0 %2,661 2,744 
Illinois Extension Pipeline Company, L.L.C.3
65.0 %584 622 
Cactus II Pipeline LLC4
30.0 %618 658 
Other30.0% - 43.8%84 76 
Gas Transmission and Midstream
Alliance Pipeline5, 7
50.0 %359 430 
Aux Sable6, 7
42.7% - 50.0%229 214 
DCP Midstream, LLC (Class A Units)8
23.4 %367 317 
Gulfstream Natural Gas System, L.L.C.50.0 %1,224 1,274 
NEXUS Gas Transmission, LLC50.0 %1,220 1,813 
Sabal Trail Transmission, LLC50.0 %1,467 1,535 
Southeast Supply Header, LLC50.0 %80 86 
Steckman Ridge, LP50.0 %87 91 
Vector Pipeline9
60.0 %191 195 
Woodfibre LNG Limited Partnership10
30.0 %777 635 
Offshore - various joint ventures22.0% - 74.3%217 314 
Gas Distribution and Storage
Other30.0% - 50.0%22 20 
Renewable Power Generation
EIH S.à r.l.11
51.0 %52 37 
Hohe See and Albatros Offshore Wind Facilities49.9 %1,701 163 
Rampion Offshore Wind Limited24.9 %391 413 
East-West Tie Limited Partnership24.1 %132 241 
Fox Squirrel Solar LLC50.0 %312 — 
Other16.4% - 50.0%110 107 
OTHER LONG-TERM INVESTMENTS
Gas Transmission and Midstream
Ara Divert HoldCo, Inc.106 — 
Other22 22 
Gas Distribution and Storage
Other24 48 
Renewable Power Generation
Other21 31 
Eliminations and Other
Other12
430 488 
  16,793 15,936 
1Owns a 49.0% interest in Bakken Pipeline Investments LLC. Bakken Pipeline Investments LLC owns 75.0% of the Bakken Pipeline System, resulting in a 27.6% effective interest in the Bakken Pipeline System by us.
2We own 90.0% of the Class B units of DCP Midstream, LLC. These units track to a 65.0% ownership in Gray Oak Pipeline, LLC (Gray Oak), resulting in a 58.5% effective interest in Gray Oak by us. On January 9, 2023, we acquired an additional 10.0% direct interest in Gray Oak for cash consideration of $230 million (US$172 million), bringing our effective interest to 68.5%.
3Owns the Southern Access Extension Project.
4On October 12, 2021, we acquired a 20.0% equity interest in Cactus II through the Moda Acquisition (Note 8). On November 2, 2022, we acquired an additional 10.0% ownership in Cactus II for cash consideration of $241 million (US$177 million), bringing our total non-operating ownership to 30.0%.
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 L.P. and Aux Sable Midstream LLC in the US.
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7On December 13, 2023, we announced that Enbridge had entered into a definitive agreement to sell its 50.0% interest in the Alliance Pipeline and interest in Aux Sable to Pembina Pipeline Corporation for $3.1 billion, including approximately $0.3 billion of non-recourse debt, subject to customary closing adjustments.
8We own 23.4% of the Class A units of DCP Midstream, LLC. These units track to a 56.5% ownership in DCP Midstream, LP (DCP), resulting in a 13.2% effective interest in DCP by us.
9Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US.
10 On November 29, 2022, we acquired an effective 30.0% interest in Woodfibre LNG Limited Partnership (Woodfibre) for cash consideration of $533 million (US$392 million). Woodfibre will operate a LNG export facility in BC being constructed by us and our partners.
11 Owns a 50.0% interest in Éolien Maritime France SAS (EMF). Through our investment in EMF, we own equity interests in three French offshore wind projects, including effective interests in Saint-Nazaire (25.5%), Fécamp (17.9%) and Calvados (21.7%).
12 Consists of investments in exchange-traded funds and debt securities held by our wholly-owned captive insurance subsidiaries. Refer to Note 23 - Risk Management and Financial Instruments.

Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees' assets at the purchase date. As at December 31, 2023, this basis difference was $3.5 billion (2022 - $3.4 billion), of which $1.7 billion (2022 - $1.5 billion) was amortizable.

For the years ended December 31, 2023, 2022 and 2021, distributions received from equity investments were $3.1 billion, $2.6 billion and $2.2 billion, respectively.

Summarized combined financial information of our unconsolidated equity investments (presented at 100%) is as follows:

Year ended December 31,2023
20221
20211
(millions of Canadian dollars)
Operating revenues22,586 30,026 22,551 
Operating expenses17,111 23,835 17,446 
Earnings4,818 5,123 3,656 
Earnings attributable to Enbridge1,816 2,056 1,600 

December 31,2023
20221
(millions of Canadian dollars)
Current assets5,842 5,328 
Non-current assets61,141 61,393 
Current liabilities6,194 5,631 
Non-current liabilities23,957 23,208 
Noncontrolling interests4,124 4,640 
1 Balances have been updated to reflect the impact of revisions made to conform to the current year's presentation. These revisions do not have an effect on our previously reported consolidated statements of earnings, comprehensive income, changes in equity, cash flows or financial position.

OTHER EQUITY INVESTMENT TRANSACTIONS
Fox Squirrel Solar LLC
On November 15, 2023, we acquired a 50% interest in a newly formed partnership with EDF Renewables North America to participate in the initial phase of a solar power facility in Ohio. Cash consideration includes an upfront payment of $157 million (US$115 million) and subsequent capital commitments up to $398 million (US$291 million). Investments past the first phase are contingent on certain conditions being met. An additional payment of $164 million (US$123 million) was made at Phase 1 in-service in December 2023.

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Hohe See and Albatros Offshore Wind Facilities
On November 3, 2023, we acquired an additional 24.45% interest in the Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities (the Offshore Wind Facilities), through the acquisition of a 49% interest in Enbridge Renewable Infrastructure Investments S.à r.l (ERII), for $391 million (€267 million) of cash and assumed debt of $524 million (€358 million), bringing our interest in the Offshore Wind Facilities to 49.9%. The Hohe See Offshore Wind Facilities and Albatros Offshore Wind Facilities are located approximately 100 kilometers off the northern coast of Germany and came into service in 2019 and 2020, respectively. Subsequent to the purchase, our interest in ERII is consolidated and our interest in the Offshore Wind Facilities will continue to be accounted for as an equity method investment included in the Renewable Power Generation segment.

DCP Midstream, LLC
On August 17, 2022, we completed a joint venture merger transaction with Phillips 66 resulting in a single joint venture, DCP Midstream, LLC, holding both our and Phillips 66's indirect ownership interests in Gray Oak and DCP. Our ownership in DCP Midstream, LLC consists of Class A and Class B Interests which track to our investments in DCP, included in the Gas Transmission and Midstream segment, and Gray Oak, included in the Liquids Pipelines segment, respectively. Through our investment in DCP Midstream, LLC, we increased our effective economic interest in Gray Oak to 58.5% from 22.8% and reduced our effective economic interest in DCP to 13.2% from 28.3%. As a result of the transaction, Enbridge assumed operatorship of Gray Oak in the second quarter of 2023.

We determined the fair value of our decrease in economic interest in DCP based on the unadjusted quoted market price of DCP's publicly traded common units on the transaction closing date. The fair value of our increased economic interest in Gray Oak was determined using the fair value prescribed to the change in our economic interest in DCP. As a result of the merger transaction and the realignment of our economic interests in DCP and Gray Oak, we also received cash consideration of approximately $522 million (US$404 million) and recorded an accounting gain of $1.1 billion (US$832 million) to Gain on joint venture merger transaction in the Consolidated Statements of Earnings. Both DCP and Gray Oak continue to be accounted for as equity method investments.

Noverco Inc.
On June 7, 2021, IPL System Inc., a wholly-owned subsidiary of Enbridge, entered into a purchase and sale agreement to sell its 38.9% common share and preferred share interest in Noverco to Trencap L.P. On December 30, 2021, we closed the sale of Noverco for cash proceeds of $1.1 billion. After closing adjustments, a gain on disposal of $303 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2021. Noverco was previously included in our Gas Distribution and Storage segment.

IMPAIRMENT OF EQUITY INVESTMENTS
PennEast Pipeline Company, LLC
PennEast Pipeline Company, LLC (PennEast) is a joint venture formed to develop a natural gas transmission pipeline to serve local distribution companies and power generators in southeastern Pennsylvania and New Jersey, is owned 20.0% by Enbridge, and is recorded as an equity method investment. In the third quarter of 2021, PennEast determined further development of the project was no longer viable and development of the project was ceased. As a result, we recorded an other-than-temporary impairment loss of $111 million on our investment for the year ended December 31, 2021 based on the estimated fair value of our share of the net assets. The carrying value of this investment was nil as at December 31, 2023 and 2022.

Our investment in PennEast formed part of our Gas Transmission and Midstream segment. The impairment loss was recorded within Income from equity investments in the Consolidated Statements of Earnings.

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14.  INTANGIBLE ASSETS

December 31, 2023Weighted Average Amortization RateCost Accumulated AmortizationNet
(millions of Canadian dollars)    
Software12.0 %1,921 (1,090)831 
Power purchase agreements4.3 %58 (24)34 
Project agreement1
4.0 %158 (41)117 
Customer relationships8.6 %2,636 (675)1,961 
Other intangible assets8.2 %603 (185)418 
Under development— %176  176 
  5,552 (2,015)3,537 

December 31, 2022Weighted Average Amortization RateCostAccumulated AmortizationNet
(millions of Canadian dollars)    
Software10.9 %2,019 (1,042)977 
Power purchase agreements4.2 %64 (23)41 
Project agreement1
4.0 %163 (36)127 
Customer relationships8.6 %2,701 (459)2,242 
Other intangible assets5.9 %621 (148)473 
Under development— %158 — 158 
  5,726 (1,708)4,018 
1Represents a project agreement acquired from the merger of Enbridge and Spectra Energy.

For the years ended December 31, 2023, 2022 and 2021, our amortization expense related to intangible assets totaled $535 million, $483 million and $348 million, respectively. Our expected amortization expense associated with existing intangible assets for each of the years 2024 to 2028 is $514 million.

15.  GOODWILL

Liquids
Pipelines
Gas
Transmission and Midstream
Gas
Distribution and Storage
Renewable Power GenerationEnergy
Services
Consolidated
(millions of Canadian dollars)
Balance at January 1, 20228,041 19,335 5,397 — 32,775 
Impairment— (2,465)— — — (2,465)
Foreign exchange and other506 1,236 — (4)— 1,738 
Acquisition3
— — — 392 — 392 
Balance at December 31, 20221,2
8,547 18,106 5,397 388 32,440 
Foreign exchange and other(205)(425) (8) (638)
Acquisition4
 46    46 
Balance at December 31, 20231,2
8,342 17,727 5,397 380 2 31,848 
1Gross goodwill as at December 31, 2023 and 2022 was $35.9 billion and $36.5 billion, respectively.
2Accumulated impairment as at December 31, 2023 and 2022 was $4.1 billion.
3In 2022, we recorded $392 million of goodwill related to the acquisition of TGE. Refer to Note 8 - Acquisitions and Dispositions.
4In 2023, we recorded $46 million of goodwill related to the acquisition of Aitken Creek. Refer to Note 8 - Acquisitions and Dispositions.

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IMPAIRMENT
Gas Transmission
During the year ended December 31, 2022, we recorded goodwill impairment of $2.5 billion related to our Gas Transmission reporting unit. The fair value of the reporting unit, determined using a combination of discounted cash flow and earnings multiples techniques, was impacted by a rise in cost of capital and lower projected long term growth rates for our existing assets. No impairment was recorded for the year ended December 31, 2023.

16.  OTHER CURRENT LIABILITIES

December 31,20232022
(millions of Canadian dollars)
Dividends payable1,975 1,825 
Deferred credits1,313 1,056 
Derivative liabilities (Note 23)
738 898 
Taxes payable596 683 
Other1,037 758 
5,659 5,220 

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17.  DEBT
December 31,
Weighted Average Interest Rate10
Maturity20232022
(millions of Canadian dollars)    
Enbridge Inc.    
US dollar senior notes4.6 %2024 - 205314,636 12,060 
Medium-term notes4.5 %2024 - 20648,598 8,223 
Sustainability-linked bonds4.7 %2032 - 20336,751 3,355 
Fixed-to-fixed subordinated term notes1
7.5 %2080 - 20847,156 3,596 
Fixed-to-floating rate subordinated term notes2
5.8 %2077 - 20785,828 6,736 
Floating rate notes3
2024791 1,491 
Fixed-to-floating non-call notes6.0 %2026923 — 
Commercial paper and credit facility draws4.7 %2024 - 20283,177 7,984 
Other4
17 15 
Enbridge (U.S.) Inc.
Commercial paper and credit facility draws5.6 %2025 - 2028670 4,199 
Other4
263 
Enbridge Energy Partners, L.P.
Senior notes6.5 %2025 - 20453,231 3,320 
Enbridge Gas Inc.
Medium-term notes4.2 %2024 - 205310,185 9,535 
Debentures9.1 %2024 - 2025210 210 
Commercial paper and credit facility draws5.2 %2025400 2,000 
Other4
2 
Enbridge Pipelines (Southern Lights) L.L.C.
Senior notes4.0 %2040791 921 
Enbridge Pipelines Inc.
Medium-term notes5
4.3 %2024 - 20535,425 5,425 
Debentures8.2 %2024200 200 
Commercial paper and credit facility draws5.4 %2025449 312 
Other4
4 — 
Enbridge Southern Lights LP
Senior notes4.0 %2040214 222 
Spectra Energy Capital, LLC
Senior notes7.0 %2032 - 2038228 234 
Algonquin Gas Transmission, LLC
Senior notes3.3 %2024 - 20291,121 1,152 
East Tennessee Natural Gas, LLC
Senior notes3.1 %2024251 258 
Texas Eastern Transmission, LP
Senior notes4.7 %2028 - 20483,362 3,455 
Spectra Energy Partners, LP
Senior notes4.3 %2024 - 20454,220 4,336 
Tri Global Energy, LLC
Senior notes 18 
Blauracke GmbH6
Senior notes2.1 %2032521 — 
Westcoast Energy Inc.
Medium-term notes4.9 %2024 - 20411,225 1,225 
Debentures8.1 %2025 - 2026275 275 
Fair value adjustment514 608 
Other7
(439)(393)
Total debt8
  81,199 80,980 
Current maturities  (6,084)(6,045)
Short-term borrowings9
  (400)(1,996)
Long-term debt  74,715 72,939 
1For an initial five or 10 years, the notes carry a fixed interest rate. Subsequently, during each reset period the interest rate will be reset to equal to the Five-Year US Treasury rate or Five-Year Government of Canada bond yield plus a margin. The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events.
2For an initial five or 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal to the Canadian Dollar Offered Rate or the Secured Overnight Financing Rate (SOFR) 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 SOFR plus a margin of 40 basis points and SOFR plus a margin of 63 basis points.
4Primarily finance lease obligations.
5Included in medium-term notes is $100 million with a maturity date of 2112.

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6In November 2023, as a part of the acquisition of an additional 49% interest in ERII, we assumed debt of $524 million (€358 million). As at December 31, 2023 $61 million (€42 million) and $460 million (€316 million) are recorded within Current portion of long-term debt and Long-term debt, respectively, on the Consolidated Statements of Financial Position. Refer to Note 13 - Long-Term Investments for further details on the transaction.
7Primarily unamortized discounts, premiums and debt issuance costs.
82023 - $37 billion, US$33 billion and €359 million; 2022 - $38 billion, US$31 billion and nil. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment.
9Weighted average interest rates on outstanding commercial paper were 5.2% as at December 31, 2023 (2022 - 4.5%).
10 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2023.

As at December 31, 2023, all outstanding debt was unsecured.

CREDIT FACILITIES
The following table provides details of our committed credit facilities as at December 31, 2023:
Maturity1
Total Facilities
Draws2
Available
(millions of Canadian dollars)    
Enbridge Inc.2024-20288,876 3,177 5,699 
Enbridge (U.S.) Inc.2025-20288,373 670 7,703 
Enbridge Pipelines Inc.20252,000 449 1,551 
Enbridge Gas Inc.20252,500 400 2,100 
Total committed credit facilities 21,749 4,696 17,053 
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.

In March 2023, Enbridge Gas increased its 364-day extendible credit facility from $2.0 billion to 2.5 billion and in July 21, 2023, the facility's maturity date was extended to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, Enbridge Pipelines Inc. extended the maturity date of its 364-day extendible credit facility to July 2025, which includes a one-year term out provision from July 2024.

In July 2023, we renewed approximately $6.8 billion of our 364-day extendible credit facilities, extending the maturity dates to July 2025, which includes a one-year term out provision from July 2024. We also renewed approximately $7.6 billion of our five-year credit facilities, extending the maturity dates to July 2028. Further, we extended our three-year credit facilities, extending the maturity dates to July 2026.

In September 2023, we obtained commitments for a US$9.4 billion senior unsecured bridge term loan credit facility to support the Acquisitions. The commitment for this facility was subsequently reduced to nil  as at December 31, 2023 as a result of the September 2023 $4.6 billion equity offering, the September 2023 subordinated long-term debt issuances, and the November 2023 senior notes long-term debt issuances.

In addition to the committed credit facilities noted above, we maintain $1.1 billion of uncommitted demand letter of credit facilities, of which $572 million was unutilized as at December 31, 2023. As at December 31, 2022, we had $1.3 billion of uncommitted demand letter of credit facilities, of which $689 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 a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2024 to 2028.

145


As at December 31, 2023 and 2022, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $3.8 billion and $10.5 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES
During the year ended December 31, 2023, we completed the following long-term debt issuances totaling US$8.5 billion and $3.9 billion:
CompanyIssue DatePrincipal Amount
(millions of Canadian dollars unless otherwise stated) 
Enbridge Inc.
March 20235.70%
sustainability-linked senior notes due March 20331
US$2,300
March 20235.97%
senior notes due March 20262
US$700
May 20234.90%medium-term notes due May 2028$600
May 20235.36%
sustainability-linked medium-term notes due May 20333
$400
May 20235.76%medium-term notes due May 2053$500
September 20238.50%
fixed-to-fixed subordinated notes due January 20844
US$1,250
September 20238.25%
fixed-to-fixed subordinated notes due January 20845
US$750
September 20238.75%
fixed-to-fixed subordinated notes due January 20846
$700
September 20238.50%
fixed-to-fixed subordinated notes due January 20847
$300
November 20235.90%senior notes due November 2026US$750
November 20236.00%senior notes due November 2028US$750
November 20236.20%senior notes due November 2030US$750
November 20236.70%senior notes due November 2053US$1,250
Enbridge Gas Inc.
October 20235.46%medium-term notes due October 2028$250
October 20235.70%medium-term notes due October 2033$400
October 20235.67%medium-term notes due October 2053$350
Enbridge Pipelines Inc.
August 20235.82%medium-term notes due August 2053$350
1The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2020.2030. If the target is not met, on September 8, 2031, the interest rate will be set to equal 5.70% plus 50 basis points.
2We have the option to call the notes at par after one year from issuance. Refer to Note 23 - Risk Management and Financial Instruments.
3The sustainability-linked senior notes are subject to a sustainability performance target of 35% reduction in emissions intensity from 2018 levels at an observation date of December 31, 2030. If the target is not met, on November 26, 2031, the interest rate will be set to equal 5.36% plus 50 basis points.
4For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.43%. Subsequent to year 10, every five years, the Five-year US treasury rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 5.18%.
5For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 3.79%. At year 10, the interest rate will be reset to equal the Five-Year US Treasury rate plus a margin of 4.04%. Subsequent to year 10, every five years, the Five-Year US Treasury rate is reset. At year 25, the interest rate will be reset to equal to the Five-Year US Treasury rate plus a margin of 4.79%.
6For the initial 10 years, the notes carry a fixed interest rate. At year 10, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.96%. Subsequent to year 10, every five years, the Government of Canada bond yield rate is reset. At year 30, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.71%.
7For the initial five years, the notes carry a fixed interest rate. At year five, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 4.30%. At year 10, the interest rate will be reset to equal the Five-Year Government of Canada bond yield plus a margin of 4.55%. Subsequent to year 10, every five years, the Five-Year Government of Canada bond yield is reset. At year 25, the interest rate will be reset to equal to the Five-Year Government of Canada bond yield plus a margin of 5.30%.
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LONG-TERM DEBT REPAYMENTS
During the year ended December 31, 2023, we completed the following long-term debt repayments totaling $1.4 billion and US$2.5 billion, respectively:
CompanyRepayment DatePrincipal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
January 20233.94%medium-term notes$275
February 2023
Floating rate notes1
US$500
April 20236.38%
fixed-to-floating rate subordinated notes2
US$600
June 20233.94%medium-term notes$450
October 20234.00%senior notesUS$800
October 20230.55%senior notesUS$500
Enbridge Gas Inc.
July 20236.05%medium-term notes$100
July 20233.79 %medium-term notes$250
Enbridge Pipelines (Southern Lights) L.L.C.
June and December 20233.98%senior notesUS$80
Enbridge Pipelines Inc.
August 20233.79%medium-term notes$250
November 20236.35%medium-term notes$100
Enbridge Southern Lights LP
June 20234.01%senior notes$9
Tri Global Energy, LLC
January 202310.00%senior notesUS$4
January 202314.00%senior notesUS$9
Year ended December 31, 2020
   (unaudited, millions of Canadian dollars)
   Cash provided by operating activities
9,781
   Adjusted for changes in operating assets and liabilities
1
(93
9,688
   Distributions to noncontrolling interests and redeemable noncontrolling interests
2
(300
   Preference share dividends
(380
   Maintenance capital expenditures
3
(915
   Significant adjustment items:
Other receipts of cash not recognized in revenue
4
292
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
1Notes carried an interest rate set to equal the SOFR plus a margin of 40 basis points.
2The five-year callable notes, with an original maturity date of April 2078, were all redeemed at par.

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, 2023, we were in compliance with all debt covenants.

ANNUAL DEBT MATURITIES
As at December 31, 2023, we have commitments as detailed below:
Total
Less
than
1 year
2 years3 years4 years5 yearsThereafter
(millions of Canadian dollars)       
Annual debt maturities1
80,438 6,067 6,405 5,630 3,377 5,307 53,652 
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.

INTEREST EXPENSE
Year ended December 31,202320222021
(millions of Canadian dollars)   
Debentures and term notes3,439 2,910 2,806 
Commercial paper and credit facility draws519 388 114 
Amortization of fair value adjustment(45)(45)(50)
Capitalized interest(101)(74)(215)
 3,812 3,179 2,655 

1
Changes in operating assets and liabilities, net of recoveries.
2
Presented net of adjusting items.
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.
65
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Our ARO relate mostly to the retirement of Contentspipelines, renewable power generation assets and obligations related to right-of way agreements and contractual leases for land use.

The discount rates used to estimate the present value of the expected future cash flows for the years ended December 31, 2023 and 2022 ranged from1.5% to 9.0%.

A reconciliation of movements in our ARO liabilities is as follows:

December 31,20232022
(millions of Canadian dollars)
Obligations at beginning of year488 502 
Liabilities acquired1 — 
Liabilities incurred 30 
Liabilities settled(23)(126)
Change in estimate and other5 51 
Foreign currency translation adjustment(6)24 
Accretion expense28 
Obligations at end of year493 488 
Presented as follows:
Other current liabilities136 83 
Other long-term liabilities357 405 
493 488 

19.  NONCONTROLLING INTERESTS

The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position:

December 31,20232022
(millions of Canadian dollars)
Algonquin Gas Transmission, LLC384 400 
Enbridge Athabasca Midstream Investor Limited Partnership1
1,086 1,106 
Maritimes & Northeast Pipeline, L.L.C.559 582 
Renewable energy assets885 1,302 
Maritimes & Northeast Pipeline Limited Partnership111 117 
Other4 
3,029 3,511 
1On October 5, 2022, we closed the sale of an 11.6% non-operating interest in certain assets from our Regional Oil Sands System to Aii. Refer to Note 8 - Acquisitions and Dispositions.

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20.  SHARE CAPITAL

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

COMMON SHARES
202320222021
December 31,Number of SharesAmountNumber of SharesAmountNumber of SharesAmount
(millions of Canadian dollars; number of shares in millions)
Balance at beginning of year2,025 64,760 2,026 64,799 2,026 64,768 
Shares issued, net of issue costs103 4,485 — — — — 
Shares issued on exercise of stock options 3 53 — 31 
Shares issued on vesting of RSUs, net of tax 12 — — — — 
Share purchases at stated value1
(3)(80)(3)(88)— — 
Other  — (4)— — 
Balance at end of year2,125 69,180 2,025 64,760 2,026 64,799 
1 Reflects the repurchase and cancellation of common shares under our normal course issuer bid.

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PREFERENCE SHARES
202320222021
December 31,Number of SharesAmountNumber of SharesAmountNumber of SharesAmount
(millions of Canadian dollars; number of shares in millions)
Preference Shares, Series A5 125 125 125 
Preference Shares, Series B20 500 20 500 18 457 
Preference Shares, Series C1
  — — 43 
Preference Shares, Series D18 450 18 450 18 450 
Preference Shares, Series F18 454 20 500 20 500 
Preference Shares, Series G2
2 46 — — — — 
Preference Shares, Series H12 291 14 350 14 350 
Preference Shares, Series I3
2 59 — — — — 
Preference Shares, Series J4
  — — 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 175
  — — 30 750 
Preference Shares, Series 1920 500 20 500 20 500 
Issuance costs(135)(135)(155)
Balance at end of year 6,818 6,818 7,747 
1On June 1, 2022, all outstanding Preference Shares, Series C were converted to Preference Shares, Series B.
2On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G.
3On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I.
4On June 1, 2022, we redeemed our US$200 million outstanding Cumulative Redeemable Preference Shares, Series J.
5On March 1, 2022, we redeemed our $750 million outstanding Cumulative Redeemable Minimum Rate Reset Preference Shares, Series 17.
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Characteristics of our outstanding preference shares are as follows:
Dividend Rate
Dividend1
Per Share Base
Redemption
Value2
Redemption and
Conversion
Option Date2,3
Right to
Convert
Into3,4
(Canadian dollars unless otherwise stated)
Preference Shares, Series A5.50 %$1.37500$25— — 
Preference Shares, Series B5.20 %$1.30052$25June 1, 2027Series C
Preference Shares, Series D5
5.41 %$1.35300$25March 1, 2028Series E
Preference Shares, Series F6
5.54 %$1.38452$25June 1, 2028Series G
Preference Shares, Series G7
6.96 %$1.90704$25June 1, 2028Series F
Preference Shares, Series H8
6.11 %$1.52800$25September 1, 2028Series I
Preference Shares, Series I9
7.19 %$1.81004$25September 1, 2028Series H
Preference Shares, Series L5.86 %US$1.46448US$25September 1, 2027Series M
Preference Shares, Series N10
6.70 %$1.67400$25December 1, 2028Series 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 111
6.70 %US$1.67592US$25June 1, 2028Series 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 1912
6.21 %$1.55300$25March 1, 2028Series 20
1The holder is entitled to receive a fixed cumulative quarterly preferential dividend, as declared by the Board of Directors. With the exception of Preference Shares, Series A, such fixed dividend rate resets every five years beginning on the initial Redemption and Conversion Option Date. Preference Shares, Series G and I contain a feature where the dividend rate resets on a quarterly basis. The Preference Shares, Series 19 contain a feature where the fixed dividend rate, when reset every five years, will not be less than 4.90%. No other series of preference shares has this feature.
2Preference Shares, Series A may be redeemed any time at our option. For all other series of preference shares, we may at our option, redeem all or a portion of the outstanding preference shares for the Per Share Base Redemption Value 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 Per Share Base Redemption Value.
4With the exception of Preference Shares, Series A, after the Redemption and Conversion Option Date, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in year) x three month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in year) x three month US Government treasury bill rate + 3.2% (Series M), 3.1% (Series 2), or 2.8% (Series 6).
5The quarterly dividend per share paid on Preference Shares, Series D was increased to $0.33825 from $0.27875 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.
6The quarterly dividend per share paid on Preference Shares, Series F was increased to $0.34613 from $0.29306 on June 1, 2023 due to reset of the annual dividend on June 1, 2023.
7On June 1, 2023, 1,827,695 of the outstanding Preference Shares, Series F were converted into Preference Shares, Series G. The quarterly dividend per share paid on Preference Shares, Series G was increased to $0.47676 from $0.47245 on December 1, 2023 due to reset on a quarterly basis.
8The quarterly dividend per share paid on Preference Shares, Series H was increased to $0.38200 from $0.27350 on September 1, 2023 due to reset of the annual dividend on September 1, 2023.
9On September 1, 2023, 2,350,602 of the outstanding Preference Shares, Series H were converted into Preference Shares, Series I. The quarterly dividend per share paid on Preference Shares, Series I was increased to $0.45251 from $0.44814 on December 1, 2023 due to reset on a quarterly basis following the date of issuance.
10 The quarterly dividend per share paid on Preference Shares, Series N was increased to $0.41850 from $0.31788 on December 1, 2023 due to reset of the annual dividend on December 1, 2023.
11 The quarterly dividend per share paid on Preference Shares, Series 1 was increased to US$0.41898 from US$0.37182 on June 1, 2023 due to reset of the annual dividend on June 1, 2023.
12 The quarterly dividend per share paid on Preference Shares, Series 19 was increased to $0.38825 from $0.30625 on March 1, 2023 due to reset of the annual dividend on March 1, 2023.

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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.

21.  STOCK OPTION AND STOCK UNIT PLANS

We maintain three primary vehicles under our long-term incentive plan (the Plan): ISOs, PSUs and RSUs. Total stock-based compensation expense recorded for the years ended December 31, 2023, 2022 and 2021 was $154 million, $260 million and $157 million, respectively. The number of common shares authorized for share-settled awards under the Plan was 181 million as at December 31, 2023, 2022 and 2021.

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, 2023Number
Weighted
Average
Exercise
Price
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
(number of options in thousands; weighted average exercise price in Canadian dollars; intrinsic value in millions of Canadian dollars)    
Options outstanding at beginning of year27,624 48.46   
Options granted3,053 53.11   
Options exercised1
(648)45.70   
Options cancelled or expired(1,300)53.84   
Options outstanding at end of year28,729 50.79 5.345 
Options vested at end of year2
20,235 50.64 4.136 
1The total intrinsic value of ISOs exercised during the years ended December 31, 2023, 2022 and 2021 was $2 million, $66 million and $24 million, respectively, and cash received on exercise was nil, $3 million and $2 million, respectively.
2The total fair value of ISOs vested during the years ended December 31, 2023, 2022 and 2021 was $20 million, $21 million and $25 million, respectively.

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Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton model are as follows:

Year ended December 31,202320222021
Fair value per option (Canadian dollars)1
6.055.074.10
Valuation assumptions
Expected option term (years)2
666
Expected volatility3
22.2 %21.9 %25.5 %
Expected dividend yield4
6.7 %6.5 %7.6 %
Risk-free interest rate5
3.5 %1.8 %0.7 %
1Options granted to US employees are based on the New York Stock Exchange prices. The option value and assumptions shown are based on a weighted average of the US and the Canadian options. The fair value per option for the years ended December 31, 2023, 2022 and 2021 were $5.38, $4.78 and $3.91, respectively, for Canadian employees and US$5.23, US$4.62 and US$3.65, 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, 2023, 2022 and 2021 for ISOs was $18 million, $15 million and $16 million, respectively. As at December 31, 2023, unrecognized compensation expense related to non-vested ISOs was $11 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.

PERFORMANCE STOCK UNITS
PSUs are granted to certain key employees where cash awards are paid following a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by Enbridge's weighted average share price for 20 days prior to the maturity of the grant and by a performance multiplier. The performance multiplier ranges from zero, if our performance fails to meet threshold performance levels, to a maximum of 2.0 if we perform within the highest range of the performance targets. The performance multiplier is derived through a calculation of our Total Shareholder Return percentile rank relative to a specified peer group of companies and our distributable cash flow per share, adjusted for unusual, infrequent or other non-operating factors, relative to targets established at the time of grant. Beginning in 2023, the performance multiplier also includes a greenhouse gas reduction component. To calculate the 2023 expense, a multiplier of 1.0 was used for 2023 PSU grants, 1.25 for 2022 PSU grants and 1.25 for the 2021 PSU grants.
December 31, 2023Number
Weighted
Average
Remaining
Contractual
Life (years)
Aggregate
Intrinsic
Value
(number of units in thousands; intrinsic value in millions of Canadian dollars)   
Units outstanding at beginning of year3,249 
Units granted2,128 
Units cancelled(214)
Units matured1
(2,218)
Dividend reinvestment235 
Units outstanding at end of year3,180 1.1175 
1The total amount paid during the years ended December 31, 2023, 2022 and 2021 for PSUs was $123 million, $90 million and $70 million, respectively.

153


Compensation expense recorded for the years ended December 31, 2023, 2022 and 2021 for PSUs was $59 million, $169 million and $56 million, respectively. As at December 31, 2023, unrecognized compensation expense related to non-vested PSUs was $54 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.

RESTRICTED STOCK UNITS
Employees may also be granted cash-settled or share-settled RSUs under the Plan. Cash-settled RSUs are paid to certain key employees, vesting in equal installments on each of the first, second and third anniversaries of the grant date. Share-settled awards are given to non-executive senior management employees and vest following a three-year maturity period. Beginning in 2023, share-settled units were granted to non-senior management employees. These units vest on each of the first, second and third anniversaries of the grant date. RSU holders receive cash or shares equal to Enbridge's weighted average share price for 20 days prior to the maturity of the grant multiplied by the number of units outstanding on the maturity date.
December 31, 2023Number
Weighted
Average
Grant Date Fair Value2
Weighted
Average
Remaining
Contractual Life (years)
Aggregate
Intrinsic Value
(number of units in thousands; intrinsic value in millions of Canadian dollars)
Units outstanding at beginning of year3,565 49.64   
Units granted1,373 52.05   
Units cancelled(246)52.06   
Units matured1
(1,401)51.05   
Dividend reinvestment280 50.88   
Units outstanding at end of year3,571 50.69 0.9177 
1The total amount paid during the years ended December 31, 2023, 2022 and 2021 for RSUs was $56 million, $32 million and $72 million, respectively.
2Weighted average grant date fair value excludes cash-settled units.

Compensation expense recorded for the years ended December 31, 2023, 2022 and 2021 for RSUs was $77 million, $76 million and $85 million, respectively. As at December 31, 2023, unrecognized compensation expense related to non-vested RSUs was $60 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.

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22.  COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

Changes in AOCI attributable to our common shareholders for the years ended December 31, 2023, 2022 and 2021 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 as at January 1, 2023121 (35)(1,137)4,348 5 218 3,520 
Other comprehensive income/(loss) retained in AOCI232 62 409 (1,695)6 (158)(1,144)
Other comprehensive (income)/loss reclassified to earnings      
Interest rate contracts1
28      28 
Foreign exchange contracts2
 (47)    (47)
Amortization of pension and OPEB actuarial gain3
     (24)(24)
 260 15 409 (1,695)6 (182)(1,187)
Tax impact      
Income tax on amounts retained in AOCI(47)(14)   28 (33)
Income tax on amounts reclassified to earnings(14)11    6 3 
 (61)(3)   34 (30)
Balance as at December 31, 2023320 (23)(728)2,653 11 70 2,303 

Cash Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
Total
(millions of Canadian dollars)
Balance as at January 1, 2022(897)— (166)56 (5)(84)(1,096)
Other comprehensive income/(loss) retained in AOCI1,125 (35)(971)4,292 (6)411 4,816 
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1
186 — — — — — 186 
Foreign exchange contracts2
(4)— — — — — (4)
Other contracts4
— — — — — 
Amortization of pension and OPEB actuarial gain3
— — — — — (14)(14)
Other— — — — 16 — 16 
1,311 (35)(971)4,292 10 397 5,004 
Tax impact
Income tax on amounts retained in AOCI(250)— — — — (99)(349)
Income tax on amounts reclassified to earnings(43)— — — — (39)
(293)— — — — (95)(388)
Balance as at December 31, 2022121 (35)(1,137)4,348 218 3,520 
155


Cash Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension and
OPEB
Adjustment
Total
(millions of Canadian dollars)
Balance as at January 1, 2021(1,326)(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 contracts5
— — — — — 
Foreign exchange contracts2
— — — — — 
Other contracts4
— — — — — 
Equity investment disposal— — — — (66)— (66)
Amortization of pension and OPEB actuarial loss and prior service costs3
— — — — — 28 28 
Other17 — — (20)— — 
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)— — — (7)(72)
(130)— — — (133)(259)
Balance as at December 31, 2021(897)— (166)56 (5)(84)(1,096)
1Reported within Interest expense in the Consolidated Statements of Earnings.
2Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.
3These components are included in the computation of net periodic benefit (credit)/cost and are reported within Other income/(expense) in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
5Reported within Transportation and other services revenues, Commodity sales, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

23.  RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK
Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market 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.

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The foreign exchange risks inherent within the CTS framework are not present in MTS. Accordingly, our foreign exchange hedging program related to the Canadian Mainline is no longer required, and the related derivatives were terminated in the first quarter of 2023 for a realized loss of $638 million.

Interest Rate Risk
Our earnings, cash flows and OCI are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors' approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a hedging program to partially mitigate the impact of short-term interest rate volatility on interest expense via the execution of floating-to-fixed interest rate swaps and costless collars. These swaps have an average fixed rate of 4.1%.

On March 8, 2023, we issued US$700 million of three-year fixed rate notes, which include the right for us to call at par after the first year. A corresponding fixed-to-floating cancellable swap was also executed which gives the swap counterparty a similar right to cancel the swap after the first year. This swap has a fixed rate of 6.0%.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to partially mitigate our exposure to long-term interest rate variability on forecasted term debt issuances via execution of floating-to-fixed interest rate swaps with an average swap rate of 3.5%.

Commodity Price Risk
Our earnings, cash flows and OCI 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 the revaluation of outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, RSUs. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS
We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. (ISDA) 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.

The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments, as well as the maximum potential settlement amounts, in the event of the specific circumstances described above. All amounts are presented gross in the Consolidated Statements of Financial Position.
157


December 31, 2023
Derivative
Instruments
Used as
Cash Flow Hedges
Derivative
Instruments
Used as
Fair Value Hedges
Non-
Qualifying
Derivative Instruments
Total Gross
Derivative
Instruments as Presented
Amounts
Available for Offset
Total Net
Derivative Instruments
(millions of Canadian dollars)     
Other current assets     
Foreign exchange contracts 41 98 139 (32)107 
Interest rate contracts31  34 65 (32)33 
Commodity contracts  418 418 (270)148 
Other contracts  1 1 (1) 
 31 41 551 623 (335)288 
Deferred amounts and other assets   
Foreign exchange contracts 16 319 335 (122)213 
Interest rate contracts51  2 53 (21)32 
Commodity contracts  75 75 (41)34 
 51 16 396 463 (184)279 
Other current liabilities   
Foreign exchange contracts (44)(84)(128)32 (96)
Interest rate contracts(183) (3)(186)32 (154)
Commodity contracts(11) (412)(423)270 (153)
Other contracts  (1)(1)1  
(194)(44)(500)(738)335 (403)
Other long-term liabilities   
Foreign exchange contracts (17)(481)(498)122 (376)
Interest rate contracts(3) (85)(88)21 (67)
Commodity contracts(7) (159)(166)41 (125)
(10)(17)(725)(752)184 (568)
Total net derivative liability   
Foreign exchange contracts (4)(148)(152) (152)
Interest rate contracts(104) (52)(156) (156)
Commodity contracts(18) (78)(96) (96)
Other contracts      
 (122)(4)(278)(404) (404)
158


December 31, 2022Derivative
Instruments
Used as
Cash Flow Hedges
Derivative
Instruments
Used as Fair Value Hedges
Non-
Qualifying
Derivative Instruments
Total Gross
Derivative
Instruments as Presented
Amounts
Available for Offset
Total Net
Derivative Instruments
(millions of Canadian dollars)     
Other current assets     
Foreign exchange contracts— — 46 46 (41)
Interest rate contracts649 — 11 660 — 660 
Commodity contracts— — 302 302 (182)120 
Other contracts— — — 
 649 — 366 1,015 (223)792 
Deferred amounts and other assets   
   Foreign exchange contracts— 156 153 309 (138)171 
   Interest rate contracts254 — — 254 — 254 
   Commodity contracts— — 61 61 (25)36 
   Other contracts— — 
 255 156 216 627 (163)464 
Other current liabilities   
   Foreign exchange contracts— (42)(524)(566)41 (525)
   Commodity contracts(48)— (284)(332)182 (150)
 (48)(42)(808)(898)223 (675)
Other long-term liabilities   
   Foreign exchange contracts— — (1,116)(1,116)138 (978)
   Interest rate contracts(3)— (1)(4)— (4)
   Commodity contracts(37)— (133)(170)25 (145)
 (40)— (1,250)(1,290)163 (1,127)
Total net derivative asset/(liability)   
   Foreign exchange contracts— 114 (1,441)(1,327)— (1,327)
   Interest rate contracts900 — 10 910 — 910 
   Commodity contracts(85)— (54)(139)— (139)
   Other contracts— 10 — 10 
 816 114 (1,476)(546)— (546)
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The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments:
20232022
As at December 31,20242025202620272028ThereafterTotalTotal
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)
1,360 500    1,860 2,155 
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)
6,582 5,327 4,697 4,091 3,162 888 24,747 27,610 
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)
30 30 28 32   120 149 
Foreign exchange contracts - Euro forwards - sell (millions of Euro)
141 126 121 81 67 195 731 697 
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)
 84,800     84,800 84,800 
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)
5,903 1,881 1,122 74 25 13 9,018 9,356 
Interest rate contracts - short-term debt receive fixed rate (millions of Canadian dollars)
918 923 174    2,015 — 
Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars)1
4,582 580     5,162 7,851 
Interest rate contracts - costless collar (millions of Canadian dollars)
 1,098 41    1,139 — 
Equity contracts (millions of Canadian dollars)
34 13     47 80 
Commodity contracts - natural gas (billions of cubic feet)
31 32 13 10   86 93 
Commodity contracts - crude oil (millions of barrels)
6      6 16 
Commodity contracts - power (megawatt per hour (MW/H))
49 (14)(26)(53)(57)(30)(22)2(14)2
1Represents the notional of long-term debt issuances hedged
2Total is an average net purchase/(sale) of power.

Derivatives Designated as Fair Value Hedges
The following table presents foreign exchange derivative instruments that are designated and qualify as fair value hedges, the realized and unrealized gain or loss on the derivative is included in Other income/(expense) or Interest expense in the Consolidated Statements of Earnings. The offsetting loss or gain on the hedged item attributable to the hedged risk is included in Other income/(expense) in the Consolidated Statements of Earnings. Any excluded components are included in the Consolidated Statements of Comprehensive Income.

Year ended December 31,20232022
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative(132)262 
Unrealized gain/(loss) on hedged item131 (254)
Realized loss on derivative(47)(110)
Realized gain on hedged item 85 

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The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
The following table presents the effect of cash flow hedges and fair value hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes:

Year ended December 31,202320222021
(millions of Canadian dollars)   
Amount of unrealized gain/(loss) recognized in OCI   
Cash flow hedges   
Foreign exchange contracts (29)
Interest rate contracts201 1,151 252 
Commodity contracts68 (53)(28)
Other contracts(2)(4)
Fair value hedges
Foreign exchange contracts15 (35)(5)
 282 1,062 191 
Amount of loss reclassified from AOCI to earnings   
Foreign exchange contracts1
 13 
Interest rate contracts2
28 186 296 
Commodity contracts3
 — 
Other contracts3
 
 28 203 304 
1Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.
2Reported within Interest expense in the Consolidated Statements of Earnings.
3Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

We estimate that a loss of $18 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 2 years as at December 31, 2023.

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 31,202320222021
(millions of Canadian dollars)   
Foreign exchange contracts1
1,292 (1,344)92 
Interest rate contracts2
(63)10 
Commodity contracts3
(41)50 71 
Other contracts4
(8)
Total unrealized derivative fair value gain/(loss), net1,180 (1,280)173 
1For the respective years ended, reported within Transportation and other services revenues (2023 - $645 million gain; 2022 - $238 million loss; 2021 - $98 million gain) and Other income/(expense) (2023 - $647 million gain; 2022 - $1,106 million loss; 2021 - $6 million loss) in the Consolidated Statements of Earnings.
2Reported as an increase within Interest expense in the Consolidated Statements of Earnings.
3For the respective years ended, reported within Transportation and other services revenues (2023 - $35 million loss; 2022 - $13 million gain; 2021 - $9 million gain), Commodity sales (2023 - $153 million gain; 2022 - $89 million gain; 2021 - $160 million gain), Commodity costs (2023 - $94 million loss; 2022 - $102 million loss; 2021 - $105 million loss) and Operating and administrative expense (2023 - $65 million loss; 2022 - $50 million gain; 2021 - $7 million gain) in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
161


LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. Our shelf prospectuses with securities regulators enable ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We were in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2023. As a result, all credit facilities are available to us and the banks are obligated to fund us under the terms of the facilities. We also identify a variety of other potential sources of debt and equity funding alternatives, including reinstatement of our dividend reinvestment and share purchase plan or at-the-market equity issuances.

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 the maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.

We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:
December 31,20232022
(millions of Canadian dollars)  
Canadian financial institutions457 644 
US financial institutions252 277 
European financial institutions107 334 
Asian financial institutions121 224 
Other1
125 105 
 1,062 1,584 
1Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.

As at December 31, 2023, we did not provide any letters of credit in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on derivative asset exposures as at December 31, 2023 and 2022.

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.

162


Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, the assessment of credit ratings and netting arrangements. Within Enbridge Gas, credit risk is mitigated by the utility's large and diversified customer base and the ability to recover an estimate for expected credit losses through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we utilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations to measure lifetime expected credit losses of receivables. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

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

FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our financial instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

Level 1
Level 1 includes financial instruments measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a financial instrument is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations, US and Canadian treasury bills, investments in exchange-traded funds held by our captive insurance subsidiaries, as well as restricted long-term investments in exchange-traded funds that are held in trust in accordance with the CER's regulatory requirements under the LMCI.

Level 2
Level 2 includes financial instrument valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Financial instruments in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the financial instrument. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross-currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.

We have also categorized the fair value of our long-term debt, investments in debt securities held by our captive insurance subsidiaries, and restricted long-term investments in Canadian government bonds held in trust in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. When possible, the fair value of our restricted long-term investments is based on quoted market prices for similar instruments and, if not available, based on broker quotes.

163


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 derivative's 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 the extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power, NGL and natural gas contracts, basis swaps, commodity swaps, and power and energy swaps, as well as physical forward commodity contracts. We do not have any other financial instruments categorized in Level 3.

We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third-party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread, as well as the credit default swap spreads associated with our counterparties, in our estimation of fair value.

Fair Value of Derivatives
We have categorized our derivative assets and liabilities measured at fair value as follows:
December 31, 2023Level 1Level 2Level 3Total Gross Derivative Instruments
(millions of Canadian dollars)    
Financial assets    
Current derivative assets    
Foreign exchange contracts 139  139 
Interest rate contracts 65  65 
Commodity contracts142 103 173 418 
Other contracts 1  1 
 142 308 173 623 
Long-term derivative assets   
Foreign exchange contracts 335  335 
Interest rate contracts 53  53 
Commodity contracts 24 51 75 
  412 51 463 
Financial liabilities   
Current derivative liabilities   
Foreign exchange contracts (128) (128)
Interest rate contracts (186) (186)
Commodity contracts(136)(76)(211)(423)
Other contracts (1) (1)
.(136)(391)(211)(738)
Long-term derivative liabilities   
Foreign exchange contracts (498) (498)
Interest rate contracts (88) (88)
Commodity contracts (22)(144)(166)
  (608)(144)(752)
Total net financial asset/(liability)   
Foreign exchange contracts (152) (152)
Interest rate contracts (156) (156)
Commodity contracts6 29 (131)(96)
Other contracts    
 6 (279)(131)(404)
164


December 31, 2022Level 1Level 2Level 3Total Gross Derivative Instruments
(millions of Canadian dollars)    
Financial assets    
Current derivative assets    
Foreign exchange contracts— 46 — 46 
Interest rate contracts— 660 — 660 
Commodity contracts65 90 147 302 
Other contracts— — 
 65 803 147 1,015 
Long-term derivative assets   
Foreign exchange contracts— 309 — 309 
Interest rate contracts— 254 — 254 
Commodity contracts— 17 44 61 
Other contracts— — 
 — 583 44 627 
Financial liabilities   
Current derivative liabilities   
Foreign exchange contracts— (566)— (566)
Commodity contracts(60)(77)(195)(332)
 (60)(643)(195)(898)
Long-term derivative liabilities   
Foreign exchange contracts— (1,116)— (1,116)
Interest rate contracts— (4)— (4)
Commodity contracts— (38)(132)(170)
 — (1,158)(132)(1,290)
Total net financial asset/(liability)   
Foreign exchange contracts— (1,327)— (1,327)
Interest rate contracts— 910 — 910 
Commodity contracts(8)(136)(139)
Other contracts— 10 — 10 
 (415)(136)(546)
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
December 31, 2023Fair ValueUnobservable InputMinimum PriceMaximum PriceWeighted Average PriceUnit of Measurement
(fair value in millions of Canadian dollars)      
Commodity contracts - financial1
      
Natural gas(6)Forward gas price2.668.293.78
$/mmbtu2
Crude(7)Forward crude price69.0192.7680.35$/barrel
Power(87)Forward power price29.75145.2459.21$/MW/H
Commodity contracts - physical1
      
Natural gas14 Forward gas price0.8611.853.42
$/mmbtu2
Crude(7)Forward crude price64.5198.1182.85$/barrel
Power(38)Forward power price18.20164.8458.46$/MW/H
 (131)     
1Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2One million British thermal units (mmbtu).
If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives.

165


Changes in the net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:

Year ended December 31,20232022
(millions of Canadian dollars)  
Level 3 net derivative liability at beginning of period(136)(108)
Total gain/(loss), unrealized  
Included in earnings1
(48)
Included in OCI67 (54)
Settlements(14)20 
Level 3 net derivative liability at end of year(131)(136)
1Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

There were no transfers into or out of Level 3 as at December 31, 2023 or 2022.

Net Investment Hedges
We currently have designated a portion of our US dollar-denominated debt as a hedge of our net investment in US dollar-denominated investments and subsidiaries.

During the years ended December 31, 2023 and 2022, we recognized unrealized foreign exchange gains of $645 million and losses of $954 million, respectively, on the translation of US dollar-denominated debt, in OCI. No unrealized gains or losses on the change in fair value of our outstanding foreign exchange forward contracts were recognized in OCI during the years ended December 31, 2023 and 2022. No realized gains or losses associated with the settlement of foreign exchange forward contracts were recognized in OCI during the years ended December 31, 2023 and 2022. During the years ended December 31, 2023 and 2022, we recognized a realized loss of $236 million and $21 million, respectively, associated with the settlement of US dollar-denominated debt that had matured during the period, in OCI.

Fair Value of Other Financial Instruments
Certain long-term investments in other entities with no actively quoted prices are classified as FVMA investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $173 million and $102 million as at December 31, 2023 and 2022, respectively.

We have wholly-owned captive insurance subsidiaries whose principal activity is providing insurance and reinsurance coverage for certain insurable property and casualty risk exposures of our operating subsidiaries and certain equity investments. As at December 31, 2023, the fair value of investments inequity funds and debt securities held by our captive insurance subsidiaries was $287 million and $284 million, respectively (2022 - $335 million and $298 million, respectively). Our investments in debt securities had a cost basis of $279 million as at December 31, 2023 (2022 - $295 million). These investments in equity funds and debt securities are recognized at fair value, classified as Level 1 and Level 2 in the fair value hierarchy, respectively, and are recorded in Other current assets and Long-term investments in the Consolidated Statements of Financial Position. There were unrealized holding gains of $34 million for the year ended December 31, 2023 (2022 - losses of $26 million).

As at December 31, 2023 and 2022, our long-term debt had a carrying value of $81.2 billion and $79.3 billion, respectively, before debt issuance costs and a fair value of $78.1 billion and $73.5 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, 2023 and 2022, the non-current notes receivable had a carrying value of $53 million and $752 million, respectively, which also approximates their fair value.

166


As at December 31, 2023 and 2022, we had investments with a fair value of $717 million and $593 million, respectively, included in Restricted long-term investments in the Consolidated Statements of Financial Position. These securities are classified as available-for-sale and represent restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with the CER's regulatory requirements.

We had restricted long-term investments held in trust totaling $263 million and $236 million as at December 31, 2023 and 2022, respectively, which are classified as Level 1 in the fair value hierarchy. We also had restricted long-term investments held in trust totaling $454 million (cost basis - $486 million) and $357 million (cost basis - $437 million) as at December 31, 2023 and 2022, respectively, which are classified as Level 2 in the fair value hierarchy. There were unrealized holding gains of $51 million and losses $122 million on these investments for the years ended December 31, 2023 and 2022, respectively. Within Other long-term liabilities we had estimated future abandonment costs related to LMCI of $745 million and $610 million as at December 31, 2023 and 2022, respectively (Note 7).
The fair value of financial assets and liabilities other than derivative instruments, certain long-term investments in other entities, restricted long-term investments, investments held by our captive insurance subsidiaries, long-term debt and non-current notes receivable described above approximate their carrying value due to the short period to maturity.

24. INCOME TAXES

INCOME TAX RATE RECONCILIATION
Year ended December 31,202320222021
(millions of Canadian dollars)   
Earnings before income taxes7,8794,5427,729
Canadian federal statutory income tax rate15 %15 %15 %
Expected federal taxes at statutory rate1,1826811,159
Increase/(decrease) resulting from:   
Provincial and state income taxes1
411108228
Foreign and other statutory rate differentials2
187295134
Effects of rate-regulated accounting3
(106)(122)(139)
Write-off of regulatory deferrals3,4
115
Part VI.1 tax, net of federal Part I deduction3,5
667673
US Minimum Tax6
100107
Non-taxable portion of gain on sale of investment3,7
(23)
Valuation allowance3
(12)65
Accounting impairment of non-deductible goodwill3,8
370
Noncontrolling interests3,9
199(17)
Investment and production tax credits(47)
Other3
(94)74(5)
Income tax expense1,8211,6041,415
Effective income tax rate23.1 %35.3 %18.3 %
1The change in provincial and state income taxes from 2022 to 2023 reflects the decrease in earnings from Canadian operations and changes to the state tax apportionment partially offset by a reduction in earnings from US operations before considering the 2022 non-deductible goodwill impairment. Refer to Note 15 - Goodwill.
2The change in foreign and other statutory rate differentials from 2022 to 2023 reflects the decrease in earnings from US operations before considering the 2022 non-deductible goodwill impairment. Refer to Note 15 - Goodwill.
3The provincial and state tax component of these items is included in the Provincial and state income taxes above.
4The amount in 2023 includes the federal tax impact of the de-recognition of rate regulated accounting for income tax relating to Southern Lights Canada and portions of the Canadian Mainline including Line 9 and L3R. Refer to Note 7 - Regulatory Matters.
5Part VI.1 tax is a tax levied on preferred share dividends paid in Canada.
6There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation.
7The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco.
8The amount in 2022 relates to the federal impact of the non-deductible goodwill impairment relating to the Gas Transmission reporting unit. Refer to Note 15 - Goodwill.
167


9The amount includes the federal tax impact of impairment to Chapman Ranch in 2023 and Magic Valley in 2022 attributable to noncontrolling interests. Refer to Note 11 - Property, Plant and Equipment.

COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES

Year ended December 31,202320222021
(millions of Canadian dollars)   
Earnings before income taxes   
Canada2,233 583 3,399 
US4,620 2,865 3,336 
Other1,026 1,094 994 
 7,879 4,542 7,729 
Current income taxes   
Canada100 360 162 
US191 201 80 
Other110 86 82 
 401 647 324 
Deferred income taxes   
Canada456 (358)344 
US974 1,309 741 
Other(10)
 1,420 957 1,091 
Income tax expense1,821 1,604 1,415 

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 31,20232022
(millions of Canadian dollars)  
Deferred income tax liabilities  
Property, plant and equipment(9,202)(9,096)
Investments(7,765)(7,099)
Regulatory assets(1,338)(1,291)
Other(52)(46)
Total deferred income tax liabilities(18,357)(17,532)
Deferred income tax assets  
Financial instruments271 456 
Loss carryforwards1,745 2,259 
Other1,798 1,723 
Total deferred income tax assets3,814 4,438 
Less valuation allowance(147)(215)
Total deferred income tax assets, net3,667 4,223 
Net deferred income tax liabilities(14,690)(13,309)
Presented as follows:
Total deferred income tax assets341 472 
Total deferred income tax liabilities(15,031)(13,781)
Net deferred income tax liabilities(14,690)(13,309)

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, 2023, we recognized the benefit of unused tax loss carryforwards of $1.3 billion (2022 - $2.1 billion) in Canada which expire in 2030 and beyond.

As at December 31, 2023, we recognized the benefit of unused tax loss carryforwards of $6.4 billion (2022 - $8.1 billion) in the US. Unused tax loss carryforwards of $0.1 billion (2022 - $0.2 billion) begin to expire in 2024, and unused tax loss carryforwards of $6.3 billion (2022 - $7.9 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 $6.6 billion and $8.0 billion for the periods ended December 31, 2023 and 2022, respectively. If such earnings are remitted, in the form of dividends or otherwise, we may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities applicable to such amounts is not practicable.

Enbridge and certain of our subsidiaries are subject to taxation in Canada, the US and other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations include the US (Federal) and Canada (Federal, Alberta and Québec). We are open to examination by Canadian tax authorities for the 2016 to 2023 tax years and by US tax authorities for the 2020 to 2023 tax years. We are currently under examination for income tax matters in Canada for the 2017 to 2020 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 31,20232022
(millions of Canadian dollars)
Unrecognized tax benefits at beginning of year55 76 
Gross decreases for tax positions of prior year(2)(17)
Change in translation of foreign currency(1)
Lapses of statute of limitations(7)(5)
Unrecognized tax benefits at end of year45 55 
The unrecognized tax benefits as at December 31, 2023, 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 both years ended December 31, 2023 and 2022 were a $1 million expense. As at December 31, 2023 and 2022, interest and penalties of $14 million and $13 million, respectively, have been accrued.

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25.  PENSION AND OTHER POSTRETIREMENT BENEFITS
PENSION PLANS
We sponsor Canadian and US contributory and non-contributory registered defined benefit and defined contribution pension plans, which provide benefits covering substantially all employees. The Canadian pension plans provide defined benefit and defined contribution pension benefits to our Canadian employees. The US pension plans provide defined benefit pension benefits to our US employees. We also sponsor supplemental non-contributory defined benefit pension plans, which provide non-registered benefits for certain employees in Canada and the US.

Defined Benefit Pension Plan Benefits
Benefits payable from the defined benefit pension plans are based on each plan participant's years of service and final average remuneration. Some benefits are partially inflation-indexed after a plan participant’s retirement. Our contributions are made in accordance with independent actuarial valuations. Participant contributions to contributory defined benefit pension plans are based upon each plan participant's current eligible remuneration.

Defined Contribution Pension Plan Benefits
Our contributions are based on each plan participant's current eligible remuneration. Our contributions for some defined contribution pension plans are also based on age and years of service. Our defined contribution pension benefit costs are equal to the amount of contributions required to be made by us.
170


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 31,2023202220232022
(millions of Canadian dollars)    
Change in projected benefit obligation    
Projected benefit obligation at beginning of year3,630 4,600 1,029 1,184 
Service cost81 131 40 43 
Interest cost184 127 47 24 
Participant contributions31 29  — 
Actuarial (gain)/loss1
359 (1,069)31 (201)
Benefits paid(193)(187)(76)(94)
Foreign currency exchange rate changes — (29)77 
Other (1)(6)(4)
Projected benefit obligation at end of year2
4,092 3,630 1,036 1,029 
Change in plan assets
Fair value of plan assets at beginning of year4,234 4,536 1,080 1,160 
Actual return/(loss) on plan assets427 (235)78 (64)
Employer contributions27 91 5 
Participant contributions31 29  — 
Benefits paid(193)(187)(76)(94)
Foreign currency exchange rate changes — (29)78 
Other2 — (6)(4)
Fair value of plan assets at end of year3
4,528 4,234 1,052 1,080 
Overfunded status at end of year436 604 16 51 
Presented as follows:
Deferred amounts and other assets636 764 116 141 
Other current liabilities(8)(9)(5)(5)
Other long-term liabilities(192)(151)(95)(85)
 436 604 16 51 
1Primarily due to the decrease in the discount rate used to measure the defined benefit obligations (2022 - primarily due to increase in the discount rate used to measure the defined benefit obligations).
2The accumulated benefit obligation for our Canadian pension plans was $3.8 billion and $3.4 billion as at December 31, 2023 and 2022, respectively. The accumulated benefit obligation for our US pension plans was $1.0 billion as at December 31, 2023 and 2022.
3Assets in the amount of $14 million (2022 - $10 million) and $62 million (2022 - $58 million), related to our Canadian and US non-registered supplemental pension plan obligations, are held in grantor trusts and rabbi trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes.

171


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 31,2023202220232022
(millions of Canadian dollars)
Accumulated benefit obligation394 360 99 89 
Fair value of plan assets243 218  — 

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 31,2023202220232022
(millions of Canadian dollars)
Projected benefit obligation416 377 99 90 
Fair value of plan assets243 218  — 

Amount Recognized in Accumulated Other Comprehensive Income
The amount of pre-tax AOCI relating to our pension plans are as follows:
 CanadaUS
December 31,2023202220232022
(millions of Canadian dollars)    
Net actuarial (gain)/loss51 (64)74 40 
Prior service cost — 1 
Total amount recognized in AOCI1
51 (64)75 41 
1Excludes amounts related to CTA.

Net Periodic Benefit (Credit)/Cost and Other Amounts Recognized in Comprehensive Income
The components of net periodic benefit (credit)/cost and other amounts recognized in pre-tax Comprehensive income related to our pension plans are as follows:
CanadaUS
Year ended December 31,202320222021202320222021
(millions of Canadian dollars)
Service cost81 131 139 40 43 44 
Interest cost1
184 127 101 47 24 17 
Expected return on plan assets1
(271)(295)(252)(77)(85)(73)
Amortization/settlement of net actuarial (gain)/loss1
 54 (4)— 11 
Amortization/curtailment of prior service credit1
 — —  (2)— 
Net periodic benefit (credit)/cost(6)(29)42 6 (20)(1)
Defined contribution benefit cost12 10  — — 
Net pension (credit)/cost recognized in Earnings6 (19)49 6 (20)(1)
Amount recognized in OCI:
 Amortization/settlement of net actuarial (gain)/loss (2)(25)4 — (11)
Amortization/curtailment of prior service credit — —  — 
Net actuarial (gain)/loss arising during the year115 (288)(291)30 (52)(99)
Total amount recognized in OCI115 (290)(316)34 (50)(110)
Total amount recognized in Comprehensive income121 (309)(267)40 (70)(111)
1Reported 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
202320222021202320222021
Projected benefit obligation
Discount rate4.6 %5.1 %3.2 %4.7 %4.9 %2.6 %
Rate of salary increase3.0 %2.9 %2.9 %2.6 %2.8 %2.8 %
Cash balance interest credit rateN/AN/AN/A4.5 %4.3 %4.3 %
Net periodic benefit cost
Discount rate5.3 %3.2 %2.6 %4.9 %2.6 %2.2 %
Rate of return on plan assets6.5 %6.6 %6.2 %7.4 %7.4 %7.3 %
Rate of salary increase2.9 %2.9 %2.3 %2.8 %2.8 %2.7 %
Cash balance interest credit rateN/AN/AN/A4.3 %4.3 %4.3 %

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.

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 31,2023202220232022
(millions of Canadian dollars)    
Change in accumulated postretirement benefit obligation    
Accumulated postretirement benefit obligation at beginning of year211 274 136 173 
Service cost3 1 
Interest cost11 6 
Participant contributions — 5 
Actuarial (gain)/loss1
13 (66)4 (37)
Benefits paid(10)(8)(20)(21)
Foreign currency exchange rate changes — (3)11 
Accumulated postretirement benefit obligation at end of year228 211 129 136 
Change in plan assets
Fair value of plan assets at beginning of year — 185 201 
Actual return/(loss) on plan assets — 14 (21)
Employer contributions10 7 
Participant contributions — 5 
Benefits paid(10)(8)(20)(21)
Foreign currency exchange rate changes — (4)13 
Fair value of plan assets at end of year — 187 185 
Overfunded/(underfunded) status at end of year(228)(211)58 49 
Presented as follows:
Deferred amounts and other assets — 73 75 
Other current liabilities(12)(12) — 
Other long-term liabilities(216)(199)(15)(26)
 (228)(211)58 49 
1Primarily due to the decrease in the discount rate used to measure the defined benefit obligations (2022 - primarily due to increase in the discount rate used to measure the benefit obligations).
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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 31,2023202220232022
(millions of Canadian dollars)
Accumulated benefit obligation228 211 78 76 
Fair value of plan assets — 63 50 

Amount Recognized in Accumulated Other Comprehensive Income
The amount of pre-tax AOCI relating to our OPEB plans are as follows:
 CanadaUS
December 31,2023202220232022
(millions of Canadian dollars)    
Net actuarial gain(82)(101)(96)(102)
Prior service credit(1)(1)(22)(30)
Total amount recognized in AOCI1
(83)(102)(118)(132)
1Excludes amounts related to CTA.

Net Periodic Benefit (Credit)/Cost and Other Amounts Recognized in Comprehensive Income
The components of net periodic benefit (credit)/cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows:
 CanadaUS
Year ended December 31,202320222021202320222021
(millions of Canadian dollars)      
Service cost3 1 
Interest cost1
11 6 
Expected return on plan assets1
 — — (11)(12)(10)
Amortization/settlement of net actuarial gain1
(6)(1)— (6)(6)(1)
Amortization/curtailment of prior service credit1
 — — (8)(7)(7)
Net periodic benefit (credit)/cost recognized in Earnings8 10 13 (18)(21)(14)
Amount recognized in OCI:
Amortization/settlement of net actuarial gain6 — 6 
Amortization/curtailment of prior service credit — — 8 
Net actuarial (gain)/loss arising during the year13 (67)(50) (4)(80)
Total amount recognized in OCI19 (66)(50)14 (72)
Total amount recognized in Comprehensive income27 (56)(37)(4)(12)(86)
1Reported within Other income/(expense) in the Consolidated Statements of Earnings.

The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligation and net periodic benefit cost of our OPEB plans are as follows:
 CanadaUS
202320222021202320222021
Accumulated postretirement benefit obligation
Discount rate4.6 %5.3 %3.2 %4.7 %4.9 %2.4 %
Net periodic benefit cost
Discount rate5.3 %3.2 %2.6 %4.9 %2.4 %2.0 %
Rate of return on plan assetsN/AN/AN/A5.9 %6.0 %6.0 %

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Assumed Health Care Cost Trend Rates
The assumed rates for the next year used to measure the expected cost of benefits are as follows:
Canada
US1
2023202220232022
Health care cost trend rate assumed for next year4.0 %4.0 %4.7 %4.7 %
Rate to which the cost trend is assumed to decline (ultimate trend rate)4.0 %4.0 %3.3 %3.3 %
Year that the rate reaches the ultimate trend rateN/AN/A2022 - 20452021 - 2045
1In addition, under the Enbridge Employee Services, Inc., Health Reimbursement Account Plan, health care costs will increase by 5.0% every three years.

PLAN ASSETS
We manage the investment risk of our pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) our operating environment and financial situation and our ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets.

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 CategoryAllocation20232022Allocation20232022
Equity securities46.0 %41.4 %38.2 %45.0 %39.5 %38.3 %
Fixed income securities23.2 %29.6 %31.7 %20.0 %19.4 %20.5 %
Alternatives1
30.8 %29.0 %30.1 %35.0 %41.1 %41.2 %
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.

175


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, 2023
Cash and cash equivalents227   227 8   8 
Equity securities4
Canada 3  3     
Global 1,871  1,871  416  416 
Fixed income securities4
Government 446  446  46  46 
Corporate 667  667  149  149 
Alternatives5
  1,290 1,290   433 433 
Forward currency contracts 24  24     
Total pension plan assets at fair value227 3,011 1,290 4,528 8 611 433 1,052 
December 31, 2022
Cash and cash equivalents272 — — 272 13 — — 13 
Equity securities4
Canada— 355 — 355 — — — — 
Global— 1,263 — 1,263 — 414 — 414 
Fixed income securities4
Government201 435 — 636 — 87 — 87 
Corporate— 433 — 433 — 121 — 121 
Alternatives5
— — 1,291 1,291 — — 445 445 
Forward currency contracts— (16)— (16)— — — — 
Total pension plan assets at fair value473 2,470 1,291 4,234 13 622 445 1,080 
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.
4Pension plan assets include $61 million (2022 - $32 million) of equity and fixed income securities investments held with related parties.
5Alternatives 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 31,2023202220232022
(millions of Canadian dollars)   
Balance at beginning of year1,291 1,064 445 337 
Unrealized and realized gains/(losses)(41)155 (12)78 
Purchases and settlements, net40 72  30 
Balance at end of year1,290 1,291 433 445 
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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, 2023
Cash and cash equivalents3   3 
Equity securities
US 36  36 
Global 62  62 
Fixed income securities
Government42 3  45 
Corporate 12  12 
Alternatives4
  29 29 
Total OPEB plan assets at fair value45 113 29 187 
December 31, 2022
Cash and cash equivalents— — 
Equity securities
US— 34 — 34 
Global— 62 — 62 
Fixed income securities
Government46 — 51 
Corporate— — 
Alternatives4
— — 28 28 
Total OPEB plan assets at fair value48 109 28 185 
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 31,20232022
(millions of Canadian dollars)
Balance at beginning of year28 22 
Unrealized and realized gains1 
Purchases and settlements, net 
Balance at end of year29 28 

177


EXPECTED BENEFIT PAYMENTS
Year ending December 31,202420252026202720282029-2033
(millions of Canadian dollars)      
Pension
Canada207 213 219 224 230 1,234 
US87 87 87 86 81 393 
OPEB
Canada13 13 13 13 13 70 
US16 15 14 13 12 49 
EXPECTED EMPLOYER CONTRIBUTIONS
In 2024, we expect to contribute approximately $18 million and $5 million to the Canadian and US pension plans, respectively, and $13 million and $6 million to the Canadian and US OPEB plans, respectively.

RETIREMENT SAVINGS PLANS
In addition to the pension and OPEB plans discussed above, we also have defined contribution employee savings plans available to US employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 6.0% of eligible pay per pay period. For the year ended December 31, 2023, pre-tax employer matching contribution costs were $33 million ($30 million in 2022 and $27 million in 2021).

26. LEASES

LESSEE
We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 1 month to 35 years as at December 31, 2023.

For the years ended December 31, 2023, 2022 and 2021, we incurred operating lease expenses of $131 million, $118 million and $95 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings.

For the years ended December 31, 2023, 2022 and 2021, operating lease payments to settle lease liabilities were $129 million, $123 million and $118 million, respectively. Operating lease payments are reported under Operating activities in the Consolidated Statements of Cash Flows.

178


Supplemental Statements of Financial Position Information
December 31, 2023December 31, 2022
(millions of Canadian dollars, except lease term and discount rate)
Operating leases1
Operating lease right-of-use assets, net2
669680
Operating lease liabilities - current3
9887
Operating lease liabilities - long-term3
652677
Total operating lease liabilities750764
Finance leases
Finance lease right-of-use assets, net4
28762
Finance lease liabilities - current5
1917
Finance lease liabilities - long-term5
26439
Total finance lease liabilities28356
Weighted average remaining lease term
Operating leases12 years12 years
Finance leases31 years5 years
Weighted average discount rate
Operating leases4.5 %4.2 %
Finance leases5.7 %4.4 %
1Affiliate ROU assets, current lease liabilities and long-term lease liabilities as at December 31, 2023 were $42 million (December 31, 2022 - $47 million), $5 million (December 31, 2022 - $5 million) and $38 million (December 31, 2022 - $43 million), respectively.
2Operating lease ROU assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position.
3Current operating lease liabilities and long-term operating lease liabilities are reported under Other current liabilities and Other long-term liabilities, respectively, in the Consolidated Statements of Financial Position.
4Finance lease ROU assets are reported under Property, plant and equipment, net in the Consolidated Statements of Financial Position.
5Current finance lease liabilities and long-term finance lease liabilities are reported under Current portion of long-term debt and Long-term debt in the Consolidated Statements of Financial Position.

As at December 31, 2023, our operating and finance lease liabilities are expected to mature as follows:
Operating leasesFinance
 leases
(millions of Canadian dollars)
2024130 31 
2025120 25 
2026106 25 
202796 18 
202875 18 
Thereafter459 502 
Total undiscounted lease payments986 619 
Less imputed interest(236)(336)
Total750 283 

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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 3 month to 28 years as at December 31, 2023.

Year ended December 31,202320222021
(millions of Canadian dollars)
Operating lease income241 266 263 
Variable lease income299 321 333 
Total lease income1
540 587 596 
1Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings.

As at December 31, 2023, our future lease payments to be received under operating lease contracts where we are the lessor are as follows:
Operating leases
(millions of Canadian dollars)
2024225 
2025206 
2026201 
2027199 
2028201 
Thereafter1,612 
Future lease payments2,644 

27. OTHER INCOME/(EXPENSE)

Year ended December 31,202320222021
(millions of Canadian dollars)   
Gain/(loss) on dispositions15 (12)319 
Realized foreign currency gain/(loss)(129)92 126 
Unrealized foreign currency gain/(loss)821 (1,094)160 
Net defined pension and OPEB credit135 239 150 
Other382 186 224 
 1,224 (589)979 

28. CHANGES IN OPERATING ASSETS AND LIABILITIES

Year ended December 31,202320222021
(millions of Canadian dollars)   
Trade receivables and unbilled revenues1,125 (572)(1,030)
Other current assets1,278 (395)(198)
Accounts receivable from affiliates18 17 (38)
Inventory763 (599)(118)
Deferred amounts and other assets23 (195)
Trade payables and accrued liabilities(1,542)585 652 
Other current liabilities339 515 (565)
Accounts payable to affiliates(66)16 52 
Interest payable199 58 43 
Other long-term liabilities174 362 (69)
 2,311 (12)(1,466)

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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.

Our transactions with significantly influenced investees are as follows:

Year ended December 31,202320222021
(millions of Canadian dollars)
Transportation and other revenues169 185 237 
Commodity sales 51 20 
Operating and administrative1
625 503 380 
Commodity costs2
63 778 790 
Gas distribution costs140 136 131 
1During the years ended December 31, 2023, 2022 and 2021, we had Operating and administrative costs from the Seaway Crude Pipeline System of $632 million, $495 million and $389 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.
2During the years ended December 31, 2023, 2022 and 2021, we had Commodity costs from Aux Sable Canada LP of $2 million, $571 million and $447 million, respectively.

LONG-TERM NOTES RECEIVABLE FROM AFFILIATES
As at December 31, 2023, amounts receivable from affiliates include a series of notes totaling $54 million (2022 - $752 million). This change in balance is primarily due to notes receivable from ERII which, beginning November 2023, eliminated upon consolidation. Refer to the Other Equity Investment Transactionssection of Note 13 - Long-Term Investments for further details on the Offshore Wind Facilities transaction. The remaining loans which require quarterly or semi-annual interest payments at annual interest rates ranging from 4% to 8%. Interest income recognized from these notes totaled $21 million, $30 million and $39 million for the years ended December 31, 2023, 2022 and 2021, respectively. The amounts receivable from affiliates are included in Deferred amounts and other assets in the Consolidated Statements of Financial position.

181


30.  COMMITMENTS AND CONTINGENCIES

COMMITMENTS
As at December 31, 2023, we have commitments as detailed below:
Total
Less
than
1 year
2 years3 years4 years5 yearsThereafter
(millions of Canadian dollars)       
Purchase of services, pipe and other materials, including transportation1
11,018 4,193 1,421 1,206 1,039 996 2,163 
Maintenance agreements2
473 51 52 52 53 34 231 
Right-of-ways commitments3
1,328 44 45 45 45 45 1,104 
Total12,819 4,288��1,518 1,303 1,137 1,075 3,498 
1Includes capital and operating commitments. Consists primarily of firm capacity payments that provide us with uninterrupted firm access to natural gas and crude oil transportation and storage contracts; contractual obligations to purchase physical quantities of natural gas; and power commitments.
2Consists primarily of maintenance service contracts for our wind and solar assets.
3Our right-of-way obligations primarily consist of non-lease agreements that existed at the time of adopting Topic 842 Leases, at which time we elected a practical expedient that allowed us to continue our historical treatment.

ENVIRONMENTAL
We are subject to various Canadian and US federal, provincial/state and local laws relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us.

Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge and its affiliates are, at times, subject to environmental remediation obligations at various sites where we operate. We manage this environmental risk through appropriate environmental policies, programs and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of costs arising from environmental incidents associated with our operating activities.

AUX SABLE
The previously reported claim filed against Aux Sable by a counterparty to an NGL supply agreement was settled and discontinued during the fourth quarter of 2023. A provision was recognized for this claim in the third quarter of 2023.

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

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

182


INSURANCE
We maintain an insurance program for us, our subsidiaries and certain of our affiliates to mitigate a certain portion of our risks. However, not all potential risks arising from our operations are insurable, or are insured by us as a result of availability, high premiums and for various other reasons. We self-insure a significant portion of certain risks through our wholly-owned captive insurance subsidiaries, which require certain assumptions and management judgments regarding the frequency and severity of claims, claim development and settlement practices and the selection of estimated loss among estimates derived using different methods. Our insurance coverage is also subject to terms and conditions, exclusions and large deductibles or self-insured retentions which may reduce or eliminate coverage in certain circumstances.
Our insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, terms, policy limits and/or deductibles can vary substantially. We can give no assurance that we will be able to maintenance adequate insurance in the future at rates or on other terms we consider commercially reasonable. In such case, we may decide to self-insure additional risks.

In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among entities on an equitable basis based on an insurance allocation agreement we have entered into with us and other subsidiaries.

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 in our Consolidated Statements of Financial Position. Performance guarantees require us to make payments to a third party if the guaranteed entity does not perform on its contractual obligations, such as debt agreements, purchase or sale agreements, and construction contracts and leases.

We typically enter into these arrangements to facilitate commercial transactions with third parties. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations, warranties or covenants, loss or damages to property, environmental liabilities, and litigation and contingent liabilities. We may indemnify third parties for certain liabilities relating to environmental matters arising from operations prior to the purchase or transfer of certain assets and interests. Similarly, we may indemnify the purchaser of assets for certain tax liabilities incurred while we owned the assets, a misrepresentation related to taxes that result in a loss to the purchaser or other certain tax liabilities related to those assets.

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, 2023, 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.

183


32.  QUARTERLY FINANCIAL DATA (UNAUDITED)

Q1Q2Q3Q4Total
(unaudited; millions of Canadian dollars, except per share amounts)
2023
Operating revenues12,075 10,432 9,844 11,298 43,649 
Operating income2,662 2,350 1,794 1,845 8,651 
Earnings1,866 2,001 623 1,568 6,058 
Earnings attributable to controlling interests1,817 1,935 621 1,818 6,191 
Earnings attributable to common shareholders1,733 1,848 532 1,726 5,839 
Earnings per common share
Basic0.86 0.91 0.26 0.81 2.84 
Diluted0.85 0.91 0.26 0.81 2.84 
2022
Operating revenues15,097 13,215 11,573 13,424 53,309 
Operating income/(loss)2,420 1,520 1,778 (540)5,178 
Earnings/(loss)2,057 607 1,383 (1,109)2,938 
Earnings/(loss) attributable to controlling interests2,029 595 1,362 (983)3,003 
Earnings/(loss) attributable to common shareholders1,927 450 1,279 (1,067)2,589 
Earnings/(loss) per common share
Basic0.95 0.22 0.63 (0.53)1.28 
Diluted0.95 0.22 0.63 (0.53)1.28 

33.  SUBSEQUENT EVENT

Acquisition of RNG Facilities
On January 2, 2024, through a wholly-owned US subsidiary, we acquired the first six Morrow Renewables operating landfill gas-to-RNG production facilities located in Texas and Arkansas for total consideration of $1.4 billion (US$1.1 billion), of which $0.5 billion (US$0.4 billion) was paid at close and $0.9 billion (US$0.7 billion) is payable within two years (the RNG Facilities Acquisition). The total consideration for all seven facilities is $1.6 billion (US$1.2 billion). The acquired assets align with and advance our low-carbon strategy.

We will account for the RNG Facilities Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations. The acquired assets and assumed liabilities will be recorded at their estimated fair values as at the date of acquisition, with any remaining amount allocated to goodwill. Due to the proximity of the acquisition date to the release date of our annual consolidated financial statements, we have not performed our initial accounting for the RNG Facilities Acquisition. The preliminary purchase price allocation will be disclosed in the first quarter of 2024 after asset and liability valuations become available.

184


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, 2023, 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, 2023, 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, 2023.

185


The effectiveness of our internal control over financial reporting as at December 31, 2023 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, 2023.

Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2023, there has been no material change in our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

NORMAL COURSE ISSUER BID
On January 4, 2023, the TSX approved our prior NCIB, which commenced on January 6, 2023 and expired on January 5, 2024. Our prior NCIB permitted us to purchase, for cancellation, up to 27,938,163 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion through the facilities of the TSX, the New York Stock Exchange and other designated exchanges and alternative trading systems.

OFFICERS AND DIRECTORS TRADING ARRANGEMENTS
Certain of our officers and directors have made elections to participate in, and are participating in, our compensation and benefit plans involving Enbridge stock, such as our 401(k) plan and directors’ compensation plan, and may from time to time make elections which may be designed to satisfy the affirmative defense conditions of Rule 10b5-1 under the Exchange Act or may constitute non-Rule 10b5-1 trading arrangements (as defined in Item 408(c) of Regulation S-K).

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.
186


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, 2023. This information will also be disclosed in the management information circular 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, 2023. This information will also be disclosed in the management information circular 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, 2023. This information will also be disclosed in the management information circular 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” for2023. 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 information circular 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.
66


Table of Contents
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this Item will be disclosed in our Form 10-K/A, which will be filed no later than 120 days after December 31, 2023. This information will also be disclosed in the management information circular that we prepare in accordance with Canadian corporate and securities law requirements.

ITEM 14. PRINCIPAL ACCOUNTANT 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, 2023. This information will also be disclosed in the management information circular that we prepare in accordance with Canadian corporate and securities law requirements.

Handling conflicts of interest and related person transactions
If a director or officer has a material interest 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.
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 must 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 space in the Houston area on behalf of Mr. Ebel and to reimburse the
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.
67
187

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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.
68

PART IV

ITEM 15. EXHIBITSEXHIBIT 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.

69
188

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
31.1*
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)
189


190


191


*
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.
192


+
+
+
+
+
+
+
+
+
+
+
+
+
+
+
193


+
+
+
+
+
+
+
+
+
+
+
+
+
+
+
+
194


+
+*
+
+
+
+
+
+
+
+
+
+
+
+
+
195


+
+
*
*
*
*
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
196

Each person whose signature appears below appoints Reginald D. Hedgebeth, Patrick R. Murray 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.
ENBRIDGE INC.
(Registrant)
(Registrant)
Date:February 9, 2024By:/s/ Gregory L. Ebel
Date: March 8, 2021By:
/s/ Colin K. Gruending
Gregory L. Ebel
President and Chief Executive Officer

197


Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 9, 2024 by the following persons on behalf of the registrant and in the capacities indicated.

/s/ Gregory L. EbelColin K. Gruending/s/ Patrick R. Murray
Gregory L. EbelPatrick R. Murray
President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
(Principal Executive Officer)(Principal Financial Officer)
/s/ Melissa M. LaForge/s/ Pamela L. Carter
Melissa M. LaForgePamela L. Carter
Senior Vice President and Chief Accounting OfficerChair of the Board of Directors
(Principal Accounting Officer)
/s/ Mayank (Mike) M. Ashar
Enbridge Inc.
/s/ Gaurdie E. Banister
Mayank (Mike) M. AsharGaurdie E. Banister
DirectorDirector
/s/ Susan M. Cunningham/s/ Jason B. Few
Susan M. CunninghamJason B. Few
DirectorDirector
/s/ Teresa S. Madden/s/ Manjit Minhas
Teresa S. MaddenManjit Minhas
DirectorDirector
/s/ Stephen S. Poloz/s/ S. Jane Rowe
Stephen S. PolozS. Jane Rowe
DirectorDirector
/s/ Dan C. Tutcher/s/ Steven W. Williams
Dan C. TutcherSteven W. Williams
DirectorDirector

71198