Company Quick10K Filing
Quick10K
Enbridge
Closing Price ($) Shares Out (MM) Market Cap ($MM)
$36.62 2,022 $74,050
10-K 2018-12-31 Annual: 2018-12-31
10-Q 2018-09-30 Quarter: 2018-09-30
10-Q 2018-06-30 Quarter: 2018-06-30
10-Q 2018-03-31 Quarter: 2018-03-31
10-K 2017-12-31 Annual: 2017-12-31
8-K 2019-02-15 Earnings, Officers, Exhibits
8-K 2019-01-23 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2019-01-23 Enter Agreement, Off-BS Arrangement, Exhibits
8-K 2018-12-20 Regulation FD, Other Events, Exhibits
8-K 2018-12-17 Regulation FD, Other Events, Exhibits
8-K 2018-12-11 Regulation FD, Exhibits
8-K 2018-11-08 Regulation FD, Other Events, Exhibits
8-K 2018-11-02 Earnings, Other Events, Exhibits
8-K 2018-09-18 Other Events, Exhibits
8-K 2018-09-18 Other Events, Exhibits
8-K 2018-09-18 Other Events, Exhibits
8-K 2018-09-17 Enter Agreement, Exhibits
8-K 2018-09-17 Enter Agreement, Exhibits
8-K 2018-09-17 Enter Agreement, Exhibits
8-K 2018-08-24 Enter Agreement, Other Events, Exhibits
8-K 2018-08-03 Earnings, Exhibits
8-K 2018-08-01 M&A, Other Events, Exhibits
8-K 2018-07-25 Officers, Exhibits
8-K 2018-05-17 Other Events, Exhibits
8-K 2018-04-09 Amend Bylaw, Other Events, Exhibits
8-K 2018-02-28 Other Events, Exhibits
8-K 2018-02-26 Amend Bylaw, Other Events, Exhibits
8-K 2018-01-26 Other Events
8-K 2018-01-21 Enter Agreement, Regulation FD, Exhibits
WGP Western Gas Equity Partners
EQGP Eqgp Holdings
DCP DCP Midstream
BPL Buckeye Partners
PAGP Plains Gp Holdings
VLP Valero Energy Partners
AROC Archrock Partners
TLP Transmontaigne Partners
CLNE Clean Energy Fuels
BKEP Blueknight Energy Partners
ENB 2018-12-31
Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Item 5.02. Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
EX-10.11 enbindemnityagreementfebru.htm
EX-21.1 a211-subsidiariesoftheregi.htm
EX-23.1 a231-consentofindependenta.htm
EX-31.1 a311-ceocertificationx3021.htm
EX-31.2 a312-cfocertificationx3021.htm
EX-32.1 a321-ceocertificationx9061.htm
EX-32.2 a322-cfocertificationx9061.htm

Enbridge Earnings 2018-12-31

ENB 10K Annual Report

Balance SheetIncome StatementCash Flow

10-K 1 ei12312018-10kxdocument.htm 10-K Document

 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_______________________________
FORM 10-K
_______________________________
x
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
or
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from         to        
Commission file number 1-10934
_______________________________
enblogocoloura01.jpg
ENBRIDGE INC.
(Exact Name of Registrant as Specified in Its Charter)
_______________________________
Canada
 
None
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)
200, 425 - 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
(Address of Principal Executive Offices) (Zip Code)
Registrant’s telephone number, including area code (403) 231-3900
_______________________________
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Shares
 
New York Stock Exchange
_______________________________
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes x No o
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 o No x
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 x No o
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 x No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer x
 
Accelerated Filer o
Non-Accelerated Filer o 
 
Smaller reporting company o
Emerging growth company o

 
 
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. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No x
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, 2018, was approximately US$61.1 billion.
As at February 8, 2019, the registrant had 2,022,657,570 common shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the proxy statement for the 2019 Annual Meeting of Shareholders are incorporated by reference in Part III.

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Page
 
PART I
  
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
PART II
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
PART III
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
PART IV
 
Item 15.
Item 16.
 
 

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GLOSSARY
AOCI
 
Accumulated other comprehensive income/(loss)
ARO
 
Asset retirement obligations
ASU
 
Accounting Standards Update
BC
 
British Columbia
bcf/d
 
Billion cubic feet per day
bpd
 
Barrels per day
CPPIB
 
Canada Pension Plan Investment Board
CTS
 
Competitive Toll Settlement
Dawn
 
Dawn Hub
DCP Midstream
 
DCP Midstream, LLC
EBITDA
 
Earnings before interest, income taxes and depreciation and amortization
ECT
 
Enbridge Commercial Trust
EEM
 
Enbridge Energy Management, L.L.C.
EEP
 
Enbridge Energy Partners, L.P.
EGD
 
Enbridge Gas Distribution Inc.
EIPLP
 
Enbridge Income Partners LP
Enbridge
 
Enbridge Inc.
ENF
 
Enbridge Income Fund Holdings Inc.
ERII
 
Enbridge Renewable Infrastructure Investments S.a.r.l.
NBEUB
 
New Brunswick Energy and Utilities Board
FERC
 
Federal Energy Regulatory Commission
Flanagan South
 
Flanagan South Pipeline
GHG
 
Greenhouse gas
HLBV
 
Hypothetical Liquidation at Book Value
IR Plan
 
EGD's Incentive Rate Plan
ISO
 
Incentive Stock Options
Lakehead System
 
Lakehead Pipeline System
LIBOR
 
London Interbank Offered Rate
LMCI
 
Land Matters Consultation Initiative
LNG
 
Liquefied natural gas
MD&A
 
Management’s Discussion and Analysis
MEP
 
Midcoast Energy Partners, L.P.
Merger Transaction
 
Combination of Enbridge and Spectra Energy through a stock-for-stock merger transaction which closed on February 27, 2017
MNPUC
 
Minnesota Public Utilities Commission
MOLP
 
Midcoast Operating, L.P. and its subsidiaries

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MW
 
Megawatts
NEB
 
National Energy Board
NGL
 
Natural gas liquids
Noverco
 
Noverco Inc.
NYSE
 
New York Stock Exchange
OCI
 
Other comprehensive income/(loss)
OEB
 
Ontario Energy Board
OPEB
 
Other postretirement benefit obligations
ROE
 
Return on equity
RSU
 
Restricted Stock Units
Sabal Trail
 
Sabal Trail Transmission, LLC
Sandpiper
 
Sandpiper Project
Seaway Pipeline
 
Seaway Crude Pipeline System
SEP
 
Spectra Energy Partners, LP
Spectra Energy
 
Spectra Energy Corp
Sponsored Vehicles buy-in
 
In the fourth quarter of 2018, Enbridge Inc. completed the buy-ins of our sponsored vehicles: Spectra Energy Partners, LP (SEP), Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEM) and Enbridge Income Fund Holdings Inc. (ENF), (collectively, the Sponsored Vehicles), where we acquired, in separate combination transactions, all of the outstanding equity securities of those Sponsored Vehicles not beneficially owned by us.
TCJA
 
Tax Cuts and Jobs Act
Texas Eastern
 
Texas Eastern Transmission, L.P.
the Fund
 
Enbridge Income Fund
the Fund and Affiliates
 
The Fund, ECT, EIPLP and the subsidiaries and investees of EIPLP
TSX
 
Toronto Stock Exchange
the Tupper Plants
 
Tupper Main and Tupper West gas plants
Union Gas
 
Union Gas Limited
U.S. GAAP
 
Generally accepted accounting principles in the United States of America
U.S. L3R Program
 
United States portion of the Line 3 Replacement Program
Vector
 
Vector Pipeline L.P.
VIE
 
Variable interest entities
WCSB
 
Western Canadian Sedimentary Basin


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CONVENTIONS

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

Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to “dollars”, “$” or “C$” are to Canadian dollars and all references to “US$” are to United States dollars. All amounts are provided on a before tax basis, unless otherwise stated.

FORWARD-LOOKING INFORMATION
 
Forward-looking information, or forward-looking statements, have been included in this Annual Report on Form 10-K to provide information about us and our subsidiaries and affiliates, including management’s assessment of our and our subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows; expected performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution, Green Power and Transmission, and Energy Services businesses; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions and expected timing thereof; estimated future dividends; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the stock-for-stock merger transaction completed on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction) including our combined scale, financial flexibility, growth program, future business prospects and performance; United States Line 3 Replacement Program (U.S. L3R Program); expected impact of the Federal Energy Regulatory Commission (FERC) policy on treatment of income taxes; the sponsored vehicle strategy, including the simplification of our corporate structure; our dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of our hedging program; and expectations resulting from the successful execution of our 2018-2020 Strategic Plan.

Although we believe these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labor and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the timing and closing of dispositions; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; expected EBITDA; expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the

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

Our forward-looking statements are subject to risks and uncertainties pertaining to the realization of anticipated benefits and synergies of the Merger Transaction, operating performance, regulatory parameters, changes in regulations applicable to our business, dispositions, the transactions undertaken to simplify our corporate structure, our dividend policy, project approval and support, renewals of rights-of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this Annual Report on Form 10-K and in our other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge Inc. assumes no obligation to publicly update or revise any forward-looking statement made in this Annual Report on Form 10-K or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.


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PART I

ITEM 1. BUSINESS

Enbridge is one of North America's largest energy infrastructure companies with strategic business platforms that include an extensive network of crude oil, liquids and natural gas pipelines, regulated natural gas distribution utilities and renewable power generation. We safely deliver in excess of three million barrels of crude oil each day in North America through our Mainline and Express pipeline, and account for approximately 62% of United States-bound Canadian crude oil exports. We also move approximately 18% of all natural gas consumed in the United States, serving key supply basins and demand markets. Our regulated utilities serve approximately 3.7 million retail customers in Ontario, Quebec and New Brunswick. We also have interests in more than 1,700 megawatts (MW) of net renewable power generation capacity in North America and Europe. Our common shares trade on the Toronto Stock Exchange (TSX) and the New York Stock Exchange (NYSE) under the symbol ENB. We were incorporated on April 13, 1970 under the Companies Ordinance of the Northwest Territories and were continued under the Canada Business Corporations Act on December 15, 1987.

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

CORPORATE VISION AND STRATEGY

VISION
Our vision is to be the leading energy infrastructure company in North America. In pursuing this vision, we play a critical role in enabling the economic well-being and quality of life of North Americans, who depend on access to plentiful energy. We transport, distribute and generate energy, and our primary purpose is to deliver the energy North Americans need and want, in the safest, most reliable and most responsible way possible.

Among our peers, we strive to be a leader in several key areas that create sustainable comparative advantage and value for shareholders including: worker and public safety, environmental protection, stakeholder relations, customer service, community investment and employee satisfaction.

STRATEGY
Last year we announced a three year plan (the Strategic Plan) focused on growing our three core business lines - Liquids Pipelines, Natural Gas Pipelines and Gas Distribution within a regulated pipeline and utility model, while improving our competitive position through streamlining our businesses and strengthening our financial position. Within each of these business lines, our assets are well positioned to provide us with the scale and diversity to compete, grow and provide the energy people need and want. Our core assets generate highly predictable cash flows and are expected to create sustainable organic growth opportunities through the expansion and extension of our existing assets.

As discussed in further detail in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, in 2018 we made significant progress on a number of the objectives set out in the Strategic Plan. Notably:

we monetized approximately $7.8 billion of non-core assets, some of which were less aligned with our regulated pipelines and utilities business model;
we strengthened our balance sheet, achieving long-term leverage targets ahead of schedule;
we streamlined and simplified our corporate structure through buying in four publicly-traded sponsored vehicles; and

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we continued to execute on our industry-leading capital program, bringing $7 billion of new projects into service during the year and advancing our Line 3 Replacement Program (L3R Program) and other secured projects currently in progress through key regulatory milestones.

As a result of the actions we took in 2018, we are entering 2019 with a streamlined business model and organizational structure, a strong balance sheet and a renewed focus on securing additional growth.

While the relative degree of emphasis has shifted with the progress we made last year, our strategic priorities remain essentially unchanged as we seek to continue to grow the business and add value in pursuit of our longer term vision. The key priorities are summarized below.

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

Maintain a Strong Financial Position
The maintenance of our financial strength is critical to our strategy. Over the last year, execution of our funding plans together with selected asset divestitures have reduced consolidated leverage and strengthened our balance sheet.

Our financing strategies are designed to achieve strong, investment grade credit ratings to ensure that we have the financial capacity to meet our capital funding needs, and the flexibility to manage capital market disruptions and respond to opportunities as they arise. Our current secured capital program, which extends beyond 2020, can be readily financed through internally generated cash flow and available balance sheet capacity without issuance of additional common equity, and we will seek to drive attractive growth post 2020 using this “self-funded” model. 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.

To reinforce our low-risk regulated pipeline and utility-like profile, we continue to closely monitor and manage controllable risks. This includes a comprehensive long-term economic hedging program to mitigate the impact of fluctuations in interest rates, foreign exchange and commodity price on our earnings and cash flow as well as ongoing monitoring and management of credit exposures to customers, suppliers and counterparties. For further details, refer to Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Execute Capital Program
Successful project execution is integral to our financial performance but also to the strategic positioning of our business over the long term. Our ongoing objective is to deliver projects on time, on budget and at the lowest practical cost while maintaining the highest standards for safety, quality, customer satisfaction and environmental and regulatory compliance. For a discussion of our current portfolio of capital projects, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

Complete Integration and Transformation
A heightened focus on efficiency and effectiveness continues to be a key priority. Given the increasingly competitive nature of our business, in 2016 we established a goal to reach top quartile cost performance while seeking opportunities to drive enhanced revenue from our operating businesses. To achieve this, we launched several projects to transform various processes, organizational capabilities and information systems infrastructure in order to improve how we do business. Several of these initiatives have been successfully completed, while others will continue into 2019 and 2020.


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A related priority for our gas distribution business is the effective integration of the operations and management of Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas) following the amalgamation of these two large natural gas distribution utilities effective January 1, 2019. The establishment of a new five-year incentive rate making model for the combined entity provides an opportunity to increase efficiencies and enhance returns while lowering customer energy costs.

Extend Growth Post 2020
Our core assets are strategically positioned between key supply basins with strong demand pull, and are underpinned by low risk commercial structures: long-term contracts, regulated cost of service tolling frameworks, established customer bases and strong risk-adjusted returns. We will remain focused on growing post 2020 through investments in these types of assets, placing an even greater emphasis on capturing the very best of a large suite of potential organic growth opportunities with an emphasis on energy export opportunities. Opportunities will be screened, analyzed and assessed using a disciplined investment framework with the objective of ensuring effective deployment of capital to achieve attractive risk-adjusted returns.

In seeking to extend growth post 2020, we will continue to focus on maintaining our low risk, regulated pipeline and utility business model, utilizing the self-funding model described above to grow our core business, while taking a rigorous approach to capital allocation. Starting in 2020, we expect to generate $5 to $6 billion of available capital to reinvest in the business without raising external equity and maintaining a strong balance sheet. We currently see many promising organic growth opportunities in which to deploy available capital in the post 2020 period but will actively monitor the business landscape and assess these opportunities against other alternative uses for our capital on an ongoing basis in order to ensure value maximization.

MAINTAIN THE FOUNDATION
Our success in executing on our strategic priorities is very much dependent on the way in which we conduct our business and the quality and capabilities of our people. These elements provide the “foundation” required to achieve our objectives and longer term vision.

Uphold Enbridge Values
We adhere to a strong set of core values that govern how we conduct our business and pursue strategic priorities, as articulated in our value statement: “Enbridge employees demonstrate safety, integrity and respect in support of our communities, the environment and each other”. Employees are expected to uphold these values in their interactions with each other, customers, suppliers, landowners, community members and all others with whom we deal and ensure our business decisions are consistent with these values. Employees and contractors are required, on an annual basis, to certify their compliance with our Statement on Business Conduct, which encapsulates these values.

Build and Maintain the Confidence of Stakeholders and Decisions Makers
Earning and sustaining the trust of our key stakeholders and decision makers is critical to our ability to execute on our growth plans and ensure that our business strategy, as well as our corporate policies and management systems, are continuously informed by the social and environmental context surrounding our projects and operations. A key priority is to establish and maintain constructive relationships with local communities and other groups directly impacted by our activities over the life-cycle of our assets. The linear nature of our energy infrastructure puts us in contact with a large number of diverse communities, landowners and regulatory bodies across North America. Because Indigenous communities have distinct rights, we have dedicated accountabilities and resources focused on Indigenous consultation and inclusion. Early identification of local concerns enables us to respond quickly and take a proactive approach to problem solving. Early engagement also enables us to provide expanded opportunities for socio-economic participation through employment, training, and procurement, as well as through the development of joint initiatives on safety, environmental and cultural protection. More broadly, our goal is to build awareness and balanced dialogue on the role and value of the energy we deliver to our society and economy. We communicate with different stakeholders, decision makers, customers and other

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interested groups, including investors, employees and the public, about the access we provide to safe, reliable, and affordable energy.

We provide annual progress updates related to the above initiatives in our annual Corporate Social Responsibility and Sustainability Report which can be found at http://csr.enbridge.com. Unless otherwise specifically stated, none of the information contained on, or connected to, the Enbridge website is incorporated by reference in, or otherwise part of, this Annual Report on Form 10-K.

Attract, Retain and Develop Highly Capable People
Investing in the attraction, retention and development of employees and future leaders is fundamental to executing our growth strategy and creating sustainability for future success. We focus on enhancing the capability of our people to maximize the potential of our organization and undertake various activities such as accelerated leadership programs, rigorous succession planning of critical roles, and facilitating career development and mobility throughout the enterprise. We also value diversity and have embedded inclusive practices throughout our programs and approach to people management. Furthermore, we strive to maintain industry competitive compensation and retention programs that provide both short-term and long-term performance incentives to our employees.

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


LIQUIDS PIPELINES

Liquids Pipelines consists of pipelines and related terminals in Canada and the United States that transport various grades of crude oil and other liquid hydrocarbons.

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enb2019liquidspipelinesa03.jpg

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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 oil and other liquid hydrocarbons within western Canada and from western Canada to the Canada/United States border near Gretna, Manitoba and Neche, North Dakota and from the United States/Canada border near Port Huron, Michigan and Sarnia, Ontario to eastern Canada and the northeastern United States. The Canadian Mainline includes six adjacent pipelines with a combined capacity of approximately 2.85 million barrels per day (bpd) that connect with the Lakehead System at the Canada/United States border, as well as five pipelines that deliver crude oil and refined products into eastern Canada and the northeastern United States. We have operated, and frequently expanded, the Canadian Mainline since 1949. The Lakehead System is the portion of the mainline system in the United States. It is an interstate common carrier pipeline system regulated by the Federal Energy Regulatory Commission (FERC), and is the primary transporter of crude oil and liquid petroleum from Western Canada to the United States.

Competitive Toll Settlement
The Competitive Toll Settlement (CTS) is the current framework governing tolls paid for products shipped on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis. The 10-year settlement was negotiated by representatives of Enbridge, the Canadian Association of Petroleum Producers and shippers on the Canadian Mainline. It was approved by the National Energy Board (NEB) on June 24, 2011 and took effect on July 1, 2011. The CTS provides for a Canadian Local Toll (CLT) for deliveries within western Canada, which is based on the 2011 Incentive Tolling Settlement toll, as well as an International Joint Tariff (IJT) for crude oil shipments originating in western Canada on the Canadian Mainline and delivered into the United States, via the Lakehead System, and into eastern Canada. These tolls are denominated in United States dollars. The IJT is designed to provide shippers on the mainline system with a stable and competitive long-term toll, thereby preserving and enhancing throughput on both the Canadian Mainline and the Lakehead System. The CLT and the IJT were both established at the time of implementation of the CTS and are adjusted annually, on July 1 of each year, at a rate equal to 75% of the Canadian Gross Domestic Product at Market Price Index published by Statistics Canada.

Although the CTS has a 10-year term, it does not require shippers to commit to certain volumes. Shippers nominate volumes on a monthly basis and we allocate capacity to maximize the efficiency of the Canadian Mainline.

Local tolls for service on the Lakehead System are not affected by the CTS and continue to be established pursuant to the Lakehead System’s existing toll agreements, as described below. Under the terms of the IJT agreement, the Canadian Mainline’s share of the IJT relating to pipeline transportation of a batch from any western Canada receipt point to the United States border is equal to the IJT applicable to that batch’s United States delivery point less the Lakehead System’s local toll to that delivery point. This amount is referred to as the Canadian Mainline IJT Residual Benchmark Toll and is denominated in United States dollars.

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Lakehead System Local Tolls
Transportation rates are governed by the FERC for deliveries from the Canada/United States border near Neche, North Dakota and from Clearbrook, Minnesota to certain principal delivery points. The Lakehead System periodically adjusts these transportation rates as allowed under the FERC’s index methodology and tariff agreements, the main components of which are 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 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 index rates, and is subject to annual adjustment on April 1.

REGIONAL OIL SANDS SYSTEM
The Regional Oil Sands System includes five intra-Alberta long haul pipelines, the Athabasca Pipeline, Waupisoo Pipeline, Woodland Pipeline, Wood Buffalo Extension/Athabasca Twin pipeline system and the Norlite Pipeline System (Norlite), as well as two large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta and the Cheecham Terminal, located south of Fort McMurray, Alberta. The Regional Oil Sands System also includes numerous laterals and related facilities which provide access for oil sands production to the system, and a long-haul intra-Alberta pipeline that transports diluent from the Edmonton, Alberta region into the oil sands producing regions located north and south of Fort McMurray, Alberta. The Regional Oil Sands System currently serves twelve producing oil sands projects.

The combined capacity of the intra-Alberta long haul pipelines is approximately 930,000 bpd to Edmonton and 1,370,000 bpd into Hardisty, with Norlite providing approximately 218,000 bpd of diluent capacity into the Fort McMurray region. The Woodland Pipeline and Norlite Pipeline System are joint ventures, 50/50 between us and Imperial Oil Resources Ventures Limited and ExxonMobil Canada Properties, and 70/30 with Keyera Corp. respectively. The Regional Oil Sands System is anchored by long-term agreements with multiple oil sands producers that include provisions for the recovery of some of the operating costs of this system.

GULF COAST AND MID-CONTINENT
Gulf Coast includes Seaway Crude Pipeline System (Seaway Pipeline), Flanagan South Pipeline (Flanagan South) and Spearhead Pipeline, as well as the Mid-Continent System comprised of the Cushing Terminal.

Seaway Pipeline
In 2011, we acquired 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. Seaway Pipeline also includes 8.8 million barrels of crude oil storage tank capacity on the Texas Gulf Coast.

The flow direction of Seaway Pipeline was reversed in 2012, enabling it to transport crude from the oversupplied hub in Cushing, Oklahoma to the Gulf Coast. Further pump station additions and modifications were completed in early 2013, increasing capacity available to shippers from an initial 150,000 bpd to approximately 400,000 bpd, depending on crude slate. In late 2014, a second line, the Seaway Pipeline Twin, was placed into service to more than double the existing capacity to 850,000 bpd. Seaway Pipeline also includes a 161-kilometer (100-mile) pipeline from the Enterprise Crude Houston crude oil terminal in Houston, Texas to the Port Arthur/Beaumont, Texas refining center.

Flanagan South Pipeline
Flanagan South is a 950-kilometer (590-mile), 36-inch diameter interstate crude oil pipeline that originates at our terminal at Flanagan, Illinois, a delivery point on the Lakehead System, and terminates in Cushing, Oklahoma. Flanagan South and associated pumping stations were completed in the fourth quarter of 2014. Flanagan South has an initial design capacity of approximately 600,000 bpd.

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Spearhead Pipeline
Spearhead Pipeline is a long-haul pipeline that delivers crude oil from Flanagan, Illinois, a delivery point on the Lakehead System, to Cushing, Oklahoma. The Spearhead pipeline was originally placed into service in 2006 and has a capacity of 193,000 bpd.

Mid-Continent System
The Mid-Continent System is comprised of storage terminals at Cushing, Oklahoma (Cushing Terminal), consisting of over 80 individual storage tanks ranging in size from 78,000 to 570,000 barrels. Total storage shell capacity of Cushing Terminal is approximately 20 million barrels. A portion of the storage facilities are used for operational purposes, while the remainder is contracted to various crude oil market participants for their term storage requirements. Contract fees include fixed monthly storage fees, throughput fees for receiving and delivering crude to and from connecting pipelines and terminals, and blending fees.

SOUTHERN LIGHTS PIPELINE
Southern Lights Pipeline is a single stream pipeline that ships diluent from the Manhattan Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. This 180,000 bpd 16/18/20-inch diameter pipeline was placed into service in 2010. Both the Canadian portion of Southern Lights Pipeline (Southern Lights Canada) and the United States portion of Southern Lights Pipeline (Southern Lights US) receive tariff revenues under long-term contracts with committed shippers. Southern Lights Pipeline capacity is 90% contracted with the remaining 10% of the capacity (18,000 bpd) assigned for shippers to ship uncommitted volumes.

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

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

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

In February 2017, we closed a transaction to acquire an effective 27.6% interest in the Bakken Pipeline System, which connects the Bakken formation in North Dakota to markets in eastern PADD II and the United States 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,

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Illinois to Nederland, Texas. Initial capacity is in excess of 500,000 bpd 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
Feeder Pipelines and Other includes a number of liquids storage assets and pipeline systems in Canada and the United States.

Key assets included in Feeder Pipelines and Other are the Hardisty Contract Terminal and Hardisty Storage Caverns located near Hardisty, Alberta, a key crude oil pipeline hub in western Canada and the Southern Access Extension (SAX) pipeline which originates out of Flanagan, Illinois and delivers to Patoka, Illinois. On July 1, 2014, Marathon executed an agreement with us to become an owner (35%) in SAX, thereby forming the Illinois Extension Pipeline Company (IEPC). We have a 65% ownership in IEPC. SAX was placed into service in December 2015 with the majority of its capacity commercially secured under long-term take-or-pay contracts with shippers.

Feeder Pipelines and Other also includes Patoka Storage, the Toledo pipeline system and the Norman Wells (NW) System. Patoka Storage is comprised of four storage tanks with 480,000 barrels of shell capacity located in Patoka, Illinois. The Toledo pipeline system connects with the Lakehead System and delivers to Ohio and Michigan. The 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
Other competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada, the United States and internationally represent competition to our liquids pipelines network. Competition amongst 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.
 
Competition also arises from proposed pipelines that seek to access markets currently served by our liquids pipelines, such as proposed projects to the Gulf Coast and from proposed projects enhancing infrastructure in the Alberta regional oil sands market. The Mid-Continent and Bakken systems also face competition from existing pipelines, proposed future pipelines and existing and alternative gathering facilities. Competition for storage facilities in the United States includes large integrated oil companies and other midstream energy partnerships. Additionally, volatile crude price differentials and insufficient pipeline capacity on either our or competitors' pipelines can make transportation of crude oil by rail competitive, particularly to markets not currently serviced by pipelines.
 
We believe that our liquids pipelines continue to provide attractive options to producers in the Western Canadian Sedimentary Basin (WCSB) and North Dakota due to our competitive tolls and flexibility through our multiple delivery and storage points. We also employ long-term agreements with shippers, which mitigates competition risk by ensuring consistent supply to our liquids pipelines network. Our current complement of growth projects to expand market access and to enhance capacity on our pipeline system are expected to provide shippers reliable and long-term competitive solutions for liquids transportation. We have a proven track record of successfully executing projects to meet the needs of our customers and our existing right-of-way for the mainline system also provides a competitive advantage as it can be difficult and costly to obtain rights-of-way for new pipelines traversing new areas.

SUPPLY AND DEMAND
We have an established and successful history of being the largest transporter of crude oil to the United States, the world’s largest market for crude oil. While United States demand for Canadian crude oil production will support the use of our infrastructure for the foreseeable future, North American and global crude oil supply and demand fundamentals are shifting, and we have a role to play in this transition by

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developing long-term transportation options that enable the efficient flow of crude oil from supply regions to end-user markets.

Higher prices in the early part of this decade encouraged production development which pushed supply beyond demand resulting in an extended price downturn starting in 2014. By the second half of 2016, drilling technology efficiencies and innovations in North America reinvigorated production growth. Oil prices continued to strengthen into 2018 on supply concerns created by sanctions being imposed on Iran; prompting Saudi Arabia and Russia to abandon rationing targets therefore reducing earlier price gains. At the same time, global demand softened in the wake of an escalating United States-China trade dispute. This resulted in the return to crude inventory builds globally.

In Western Canada, lack of export pipeline capacity resulted in the rapid buildup of inventories and extreme discounts of Western Canadian crude; WCS discounts peaked at over US$50 per barrel against WTI in October. This, in turn, resulted in the Alberta Government entering into negotiations to purchase 7,000 rail cars and 80 engines to add about 120,000 bpd of rail export capacity for the industry by the end of 2020, and the adoption of a production curtailment policy directing the industry in the province to shut in 325,000 bpd starting January 1, 2019. The aim of this policy is to both draw down inventories by approximately 20 million barrels and return crude discounts to more historical norms. The policy calls for curtailment levels to be reduced as inventory levels ratchet down and new pipeline and rail capacity come on line. Western Canadian crude prices responded almost immediately upon the release of the curtailment adoption notice, with discounts narrowing to around US$10 per barrel. The discount at this level would imply that rail is not financially attractive, and hence frustrating the government's efforts to draw down inventories.

Notwithstanding the current price environment and Alberta policies, our mainline system has thus far continued to be highly utilized. Mainline throughput as measured at the Canada/United States border at Gretna, Manitoba saw record deliveries of 2.8 million bpd in November 2018. The mainline system continues to be subject to apportionment, as nominated volumes currently exceed capacity on portions of the system. The impact of a low crude oil price environment on the financial performance of our liquids pipelines business is expected to be relatively modest given the cost effectiveness of our mainline toll, and commercial arrangements which underpin many of the pipelines providing a significant measure of protection against volume fluctuations. Our mainline system is well positioned to continue to provide safe and efficient transportation which will enable western Canadian and Bakken production to reach attractive markets in the United States and eastern Canada at a competitive cost relative to other alternatives.

The fundamentals of oil sands production and steep discounts for Western Canadian crude have caused some sponsors to reconsider the timing of future projects. While recently updated forecasts continue to reflect long-term supply growth from the WCSB, the projected pace of growth is slower than previous forecasts as companies continue to assess the viability of capital investments in light of the current price environment and ongoing uncertainty with respect to the timing and completion of new pipeline systems proposed by our competitors.

Over the long term, continued growth in global energy consumption is expected to be primarily driven by emerging economies in regions outside the Organization for Economic Cooperation and Development (OECD), mainly in India and China. In North America, demand growth for transportation fuels is expected to moderate due to vehicle fuel efficiencies and increasing sales of electric vehicles. Accordingly, there is a strategic opportunity to establish tide-water export facilities to service North American producers wanting access to global markets.

Global crude oil production is expected to continue to grow through 2035, primarily by North America, Brazil and Organization of Petroleum Exporting Countries (OPEC). Growth in supply from OPEC is partly due to the expected recovery of Iraqi and Libyan production. Over the longer term, North American production from tight oil plays is expected to grow as technology continues to improve well productivity and efficiencies. The pace of growth in North America and level of investment in the WCSB could be

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tempered in future years by a number of factors including a sustained period of low crude oil prices and corresponding production decisions by OPEC, increasing environmental regulation, and prolonged approval processes for new pipelines with access to tide-water for export or to United States markets.

In recent years, the combination of relatively flat domestic demand, growing supply and long-lead time to build pipeline infrastructure led to a fundamental change in the North American crude oil landscape. The inability to move increasing inland supply to markets resulted in a divergence between WTI and world pricing, resulting in lower netbacks for North American producers. The impact of price differentials has been even more pronounced for western Canadian producers as insufficient pipeline infrastructure resulted in a further discounting of Alberta crude relative to WTI. New pipeline capacity is expected to come online in 2019, further stabilizing differentials in western Canada and the end to the government curtailment program. Canadian pipeline export capacity is expected to remain fully utilized, resulting in continued apportionment on our mainline system and incremental production utilizing non-pipeline transportation services (e.g. rail and trucks) until such time as sufficient pipeline capacity is made available. Over the longer term, however, we believe pipelines will continue to be the most reliable and cost-effective means of transportation.

Our role in helping to address the evolving supply and demand fundamentals and alleviating price discounts for producers and supply costs to refiners is through optimization of throughput on our existing liquids pipelines systems and through investment in new pipelines and related infrastructure to provide expanded transportation capacity and sustainable connectivity to alternative markets. Progress on the development and construction of our commercially secured growth projects is discussed in Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

GAS TRANSMISSION & MIDSTREAM
Gas Transmission and Midstream consists of our investments in natural gas pipelines and gathering and processing facilities in Canada and the United States, including US Gas Transmission, Canadian Gas Transmission and Midstream, Alliance Pipeline, US Midstream and other assets.

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

The Texas Eastern natural gas transmission system extends approximately 2,735-kilometers (1,700-miles) from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York. Texas Eastern's onshore system consists of approximately 14,597-kilometers (9,070-miles) of pipeline and associated compressor stations. Texas Eastern is also connected to four affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas Transmission business.

The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends approximately 402-kilometers (250-miles) through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to M&N U.S. The system consists of approximately 1,835-kilometers (1,140-miles) of pipeline with associated compressor stations. We indirectly own 92% of the Algonquin natural gas transmission system.

M&N U.S. is an approximately 563-kilometer (350-mile) mainline interstate natural gas transmission system, including associated compressor stations, which extends from northeastern Massachusetts to the border of Canada near Baileyville, Maine. M&N U.S. is connected to the Canadian portion of the Maritimes & Northeast Pipeline system, M&N Canada (see Gas Transmission and Midstream - Canadian Gas Transmission and Midstream). We indirectly own 78% of M&N U.S.

East Tennessee’s natural gas transmission system crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems totaling approximately 2,470-kilometers (1,535-miles) of pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East Tennessee has a Liquefied Natural Gas (LNG) storage facility in Tennessee and also connects to the Saltville storage facilities in Virginia.

Gulfstream is an approximately 1,199-kilometer (745-mile) interstate natural gas transmission system with associated compressor stations, operated jointly with The Williams Companies, Inc. Gulfstream transports natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and southern Florida. We indirectly own 50% of Gulfstream.

Sabal Trail is an approximately 829-kilometer (515-mile) pipeline that provides firm natural gas transportation to Florida Power & Light Company for its power generation needs and will deliver natural gas to Duke Energy Florida's natural gas plant. Facilities include a pipeline, laterals and various compressor stations. The pipeline infrastructure is located in Alabama, Georgia and Florida, and adds approximately 1.1 billion cubic feet per day (bcf/d) of new capacity enabling the access of onshore shale gas supplies once approved future expansions are completed. We indirectly own 50% of Sabal Trail.

NEXUS, which was placed into service in October 2018, is an approximately 410-kilometer (255-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, and adds approximately 1.5 bcf/d of new capacity. Through its interconnect with Vector, NEXUS provides a connection to Dawn Hub (Dawn), the largest integrated underground storage facility in Canada and one of the largest in North America, located in southwestern Ontario adjacent to the Greater Toronto Area. We indirectly own 50% of NEXUS.

Valley Crossing, which was placed into service in October 2018, is an approximately 274-kilometer (170-mile) intrastate natural gas transmission system, with associated compressor stations. The pipeline

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infrastructure is located in Texas and provides market access of up to 2.6 bcf/d to the Comisión Federal de Electricidad (CFE), Mexico’s state-owned utility.

SESH is an approximately 467-kilometer (290-mile) natural gas transmission system with associated compressor stations, operated jointly with Enable Gas Transmission, LLC. 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. We indirectly own 50% of SESH.
 
Vector is a 560-kilometer (348-mile) pipeline that transports 1.3 bcf/d of natural gas from Joliet, Illinois in the Chicago area to parts of Indiana, Michigan and Ontario. We indirectly own 60% of Vector.

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

Interruptible transmission and storage services are also available where customers can use capacity if it exists at the time of the request 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 AND MIDSTREAM
Canadian Gas Transmission and Midstream includes the Western Canada Transmission & Processing businesses, which is comprised of British Columbia Pipeline & Field Services, M&N Canada and certain other midstream gas pipelines, gathering, processing and storage assets.

British Columbia Pipeline and British Columbia Field Services provide fee-based natural gas transmission and gas gathering and processing services. British Columbia Pipeline has approximately 2,897-kilometers (1,800-miles) of transmission pipeline in British Columbia and Alberta, as well as associated mainline compressor stations. The British Columbia Field Services business includes eight gas processing plants located in British Columbia, associated field compressor stations and approximately 2,253-kilometers (1,400-miles) of gathering pipelines.

On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses, inclusive of six gas processing plants, to Brookfield Infrastructure Partners L.P. and its institutional partners. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations. On October 1, 2018, we closed the sale of the provincially regulated facilities and the sale of the federally regulated facilities is expected to close in mid-2019. For further information, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Asset Monetization.

M&N Canada is an approximately 885-kilometer (550-mile) interprovincial natural gas transmission mainline system which extends from Goldboro, Nova Scotia to the United States border near Baileyville, Maine. M&N Canada is connected to M&N U.S. For further information, refer to Gas Transmission and Midstream - US Gas Transmission. We indirectly own 78% of M&N Canada.

The majority of transportation services provided by Canadian Gas Transmission and Midstream are under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline, plus a small variable component that is based on volumes transported to recover variable costs. Canadian Gas Transmission and Midstream also provides

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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.

ALLIANCE PIPELINE
Alliance Pipeline is a 3,000-kilometer (1,864-mile) integrated, high-pressure natural gas transmission pipeline and approximately 860-kilometers (534-miles) of lateral pipelines and related infrastructure. It transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub downstream of the Aux Sable NGL extraction and fractionation plant at Channahon, Illinois. The majority of transportation services provided by Alliance pipeline are under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline. Alliance pipeline also provides interruptible transmission services where customers can use capacity if it is available at the time of request. We indirectly own 50% of Alliance Pipeline.

US MIDSTREAM
On August 1, 2018, we closed the sale of our Midcoast assets to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC). For further information, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Asset Monetization. These assets consist of the Anadarko, East Texas, North Texas and Texas Express NGL systems. These assets include natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. Midcoast also has rail and liquids marketing operations.

US Midstream still includes a 42.7% interest in each of Aux Sable Liquid Products LP and Aux Sable Midstream LLC, and a 50% interest in Aux Sable Canada LP (collectively, Aux Sable). Aux Sable Liquid Products LP owns and operates an NGL extraction and fractionation plant at Channahon, Illinois, outside Chicago, near the terminus of Alliance Pipeline. Aux Sable also owns facilities upstream of Alliance Pipeline that facilitate deliveries of liquids-rich gas volumes into the pipeline for further processing at the Aux Sable plant. These facilities include the Palermo Conditioning Plant and the Prairie Rose Pipeline in the Bakken area of North Dakota, owned and operated by Aux Sable Midstream US; and Aux Sable Canada’s interests in the Montney area of British Columbia, comprising the Septimus Pipeline and the Septimus and Wilder Gas Plants.

US Midstream also includes a 50% investment in DCP Midstream, LLC (DCP Midstream), which indirectly owns approximately 38% of DCP Midstream, LP, including limited partner and general partner interests. DCP Midstream, LP is a midstream master limited partnership, with a diversified portfolio of assets, engaged in the business of gathering, compressing, treating, processing, transporting, storing and selling natural gas; producing, fractionating, transporting, storing and selling NGLs; and recovering and selling condensate. DCP Midstream, LP owns and operates more than 49 plants and approximately 99,780-kilometers (62,000-miles) of natural gas and natural gas liquids pipelines, with operations in 17 states across major producing regions.
 
OTHER
Other consists primarily of our offshore assets. Enbridge Offshore Pipelines is comprised of 11 active natural gas gathering and FERC regulated transmission pipelines and four active oil pipelines. These pipelines are located in four major corridors in the Gulf of Mexico, extending to deepwater developments, and include almost 2,100-kilometers (1,300-miles) of underwater pipe and onshore facilities with total capacity of approximately 6.5 bcf/d.
 
COMPETITION
Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The flow pattern of natural gas is changing across North America due to emerging supply sources and evolving demand centers, which

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creates competition for growth opportunities. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service.

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

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

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 natural gas fundamentals over the last decade, and will continue to play a part as the energy landscape evolves. Shifts in production and consumption, both domestic and foreign, will require that we continue to serve as a critical link between markets.

At the close of the last decade, natural gas production in each of the Appalachian and Permian basins was less than 5.0 bcf/d each. Today, these regions produce more than 40.0 bcf/d of natural gas on a combined basis. Improved technology and increased shale gas drilling has increased the supply of low cost natural gas. As well, there has been and continues to be a corresponding increase in demand for our natural gas infrastructure in North America. Through a series of expansions and reversals on our core systems, combined with the execution of greenfield projects and strategic acquisitions, we have been able to meet the needs of producers and consumers alike. Our United States Gas Transmission systems were initially designed to transport natural gas from the Gulf Coast to the supply starved northeast markets. Our asset base now has the capability to transport diverse supply to the northeast, southeast, midwest, and gulf coast markets on a fully subscribed and highly utilized basis.

The northeast market continues its role as a predominantly supply constrained region with steady growth. Natural gas demand in the northeast is expected to grow by 3.1 bcf/d through 2035, driven by continued commercial and residential load growth. Natural gas leads the fuel mix of the Independent System Operator New England market at more than 40 percent. The bidirectional capabilities offered by our system allow us to deliver both domestic and imported supplies to our regional customers, 75 percent of whom are local distribution companies with a contract renewal rate of 98 percent. The region has seen an increase in natural gas supply due to the development of the Marcellus and Utica shales in the Appalachia region.

Demand for natural gas in the southeast region is forecast to increase by 3.5 bcf/d through 2035. Generating capacity in Florida is expected to grow 15 percent by 2026, the majority of which is projected to be natural gas-fired. 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 continues to grow by approximately 3.0 bcf/d over the next two decades, maintaining this link will remain important. Flexibility in supply for this market is especially critical to maintaining liquidity and price stability as natural gas continues to replace coal fired generation.

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Gulf coast demand growth is being driven by an ongoing wave of gas-intensive petrochemical facilities which are now starting to enter service, along with power generation, an increase in the volume of LNG exports and additional pipeline exports to Mexico. Demand in the region is anticipated to grow by more than 6.0 bcf/d through 2035. 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, LNG and LPG exports see strong growth. The United States exported approximately 3.0 bcf/d of natural gas from the gulf coast region at the end of 2018 with an export capacity of approximately 10.0 bcf/d scheduled to be in service by 2021.

Despite there being strong growth in both supply and demand in the United States, a lack of adequate transportation capacity has placed downward pressure on local natural gas pricing. The Appalachian Basin has seen price differentials of $1.00 to $2.00 per MMBtu relative to Henry Hub in the gulf coast over the last few years. As 3.0 bcf/d of new capacity out of the region came online in late 2018, half of which is on our newly constructed assets, the differential between northeast production and downstream markets has significantly strengthened. Unlike the dry gas production of the Marcellus, natural gas production growth in the Permian Basin is a result of robust crude oil production taking place in the region. Associated gas supplies from the region increased by approximately 4.0 bcf/d over the past two years and growth is forecasted to continue for the next decade. Until new natural gas transportation capacity begins to come online in the second half of 2019, the natural gas prices in the region will continue to remain low relative to other producing regions.

Western Canada is experiencing a similar phenomenon to that of the Permian, with the local markets experiencing very low or even negative prices for natural gas, as transportation bottlenecks continue. One of the few vital links to demand centers in the pacific northwest are our own systems in the region which operate near full capacity. As demand for supply out of the WCSB continues to grow, driven largely by NGL production and local oil sands production, the need for new natural gas and NGL infrastructure will continue to rise.

Global energy demand is expected to increase approximately 30 percent by 2035, according to the International Energy Agency, driven primarily by economic growth in non-OECD countries. Natural gas will play an important role in meeting this energy demand as gas consumption is anticipated to grow by approximately 45 percent during this period as one of the world’s fastest growing energy sources. North American exports will play a significant part in meeting global demand, underscoring the ability of our assets to remain highly utilized by shippers, and highlighting the need for incremental transportation solutions across North America. In response to these global fundamentals, we believe we are well positioned to provide value-added solutions to shippers. We are responding to the need for regional infrastructure with additional investments in Canadian and United States gas transportation facilities. Progress on the development and construction of our commercially secured growth projects is discussed in Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Growth Projects - Commercially Secured Projects.

GAS DISTRIBUTION
Gas Distribution consists of our natural gas utility operations, the core of which are EGD and Union Gas, which serve residential, commercial and industrial customers, primarily located throughout Ontario. This business segment also includes natural gas distribution activities in Quebec and New Brunswick and an investment in Noverco Inc (Noverco).
On August 30, 2018, we received a decision from the Ontario Energy Board (OEB) approving the application to amalgamate EGD and Union Gas (Amalgamation). On October 15, 2018, we announced that we would proceed with the Amalgamation, with an expected effective date of January 1, 2019. On

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January 1, 2019, the Amalgamation was completed and the amalgamated company continued as Enbridge Gas Inc.

The OEB decision also approved the rate setting mechanism for the amalgamated entity to be employed during a five-year deferred rebasing period from 2019 through 2023, after which time rates will be rebased. The decision also approved the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires the amalgamated entity to share equally with customers, any earnings in excess of 150 basis points over the OEB approved return on equity (ROE).

The Amalgamation, on January 1, 2019, created the single largest natural gas utility in North America in terms of send-out volumes, and third largest in terms of number of customers. We expect that this will drive efficiencies and synergies, leverage greater supply-chain strength, create new opportunities for growth, and form a stronger platform to deliver strong, predictable returns to shareholders and superior value and service to customers.

Given the timing of the Amalgamation, this Annual Report on Form 10-K continues to provide separate descriptions of EGD and Union Gas and separate discussions of the operating and financial performance of each of those entities for the year ended December 31, 2018. Post-Amalgamation, the management and operations of EGD and Union Gas will become integrated and the operating and financial results of Enbridge Gas Inc. will reflect the combined performance of the two legacy utility operations.

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ENBRIDGE GAS DISTRIBUTION
EGD is a rate-regulated natural gas distribution utility serving approximately 2.2 million residential, commercial and industrial customers in its franchise areas of central and eastern Ontario. In addition, EGD currently serves areas in northern New York State through St. Lawrence Gas Company Inc. (St. Lawrence Gas). In August 2017, EGD entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas. The transaction is expected to close in 2019, subject to regulatory approval and certain pre-closing conditions.

EGD also owns and operates regulated and unregulated natural gas storage facilities in Ontario. The utility business is conducted under statutes and municipal bylaws which grant the right to operate in the areas served. The utility operations of EGD and St. Lawrence Gas are regulated by the OEB and by the New York State Public Service Commission, respectively.

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As at December 31, 2018, EGD owned and operated a network of approximately 83,000-kilometers (51,574-miles) of mains for the distribution of natural gas, as well as the service pipes to transfer natural gas from mains to meters on customers' premises.

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

Distribution
EGD's principal source of revenue arises from distribution of natural gas to customers. The services provided to residential, commercial and industrial heating customers are primarily on a general service basis (without a specific fixed term or fixed price contract). The services provided to larger commercial and industrial customers are usually on an annual contract basis under firm or interruptible service contracts.

Transportation
EGD relies on its long-term contracts with Union Gas, an affiliated company under common control, for transportation of natural gas from Dawn. These contracts effectively provide EGD with access to United States sourced natural gas at Dawn. These contracts also provide transportation for natural gas received at Dawn via Vector as well as natural gas stored at EGD's and Union Gas' storage pools. Key pipeline interconnects enabled EGD to deliver approximately 449 bcf of gas through EGD's distribution and transmission system in 2018.

In addition, EGD contracts for firm transportation service with TransCanada Corporation (TransCanada) 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 EGD flexibility in obtaining its customer's natural gas supply and accommodating the requests of its direct purchase customers for assignment of TransCanada capacity. EGD forecasts the natural gas supply needs of its customers, including the associated transportation and storage requirements.

Storage
EGD’s business is highly seasonal as daily market demand for natural gas fluctuates with changes in weather, with peak consumption occurring in the winter months. Utilization of storage facilities permits EGD to take delivery of natural gas on favorable terms during offpeak summer periods for subsequent use during the winter heating season. This practice permits EGD to minimize the annual cost of transportation of natural gas from its supply basins, assists in reducing its overall cost of natural gas supply and adds a measure of security in the event of any short-term interruption of transportation of natural gas to EGD's franchise area. EGD's principal storage facilities are located in southwestern Ontario, near Dawn, and have a total working capacity of approximately 109 bcf in 11 underground facilities located in depleted gas fields. 99 petajoules (PJs) of the total working capacity is available to EGD for utility operations. EGD also has storage contracts with third parties for 6 bcf of storage capacity.

UNION GAS
Union Gas is a rateregulated natural gas distribution utility that currently serves approximately 1.5 million residential, commercial and industrial customers in its franchise areas of northern, southwestern and eastern Ontario.

Union Gas' regulated and unregulated storage and transmission business offers storage and transmission services to customers at Dawn. It offers customers an important link in the movement of natural gas from western Canada and United States supply basins to markets in central Canada and the northeastern United States. The utility business is conducted under statutes and municipal bylaws which grant the right to operate in the areas served. The utility operations of Union Gas are regulated by the OEB.


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As at December 31, 2018, Union Gas owned and operated a network of approximately 67,000-kilometers (41,632-miles) of mains for the transportation and distribution of natural gas, as well as the service pipes to transfer natural gas from mains to meters on customers' premises.

Similar to EGD, there are three principal interrelated aspects of the natural gas distribution business in which Union Gas is directly involved: Distribution, Transportation and Storage.

Distribution
Union Gas’ principal source of revenue arises from distribution of natural gas to customers. The services provided to residential, small commercial and industrial heating customers are primarily on a general service basis (without a specific fixed term or fixed price contract). The services provided to larger commercial and industrial customers are underpinned by firm or interruptible service contracts.

Transportation
Union Gas’ transmission system consists of approximately 5,000-kilometers (3,107-miles) of high-pressure pipeline and five mainline compressor stations. Key pipeline interconnects in Canada and the United States enabled Union Gas to deliver approximately 1,372 bcf of gas through Union Gas’ distribution and transmission system in 2018. Union Gas’ transmission system also links an extensive network of underground storage pools at Dawn to major Canadian and United States markets. There are multiple pipelines providing access to Dawn. Customers can purchase both firm and interruptible transportation services on the Union Gas system. As the supply of natural gas in areas close to Ontario continues to grow, there is an increased demand to access these diverse supplies at Dawn and transport them along the Dawn-Parkway pipeline system to markets in Ontario, eastern Canada and the northeastern United States. As of November 1, 2017, the transmission system has an effective peak daily demand capacity of 7.5 bcf/d. A substantial amount of Union Gas’ transportation revenue is generated by fixed annual demand charges, with the average length of a long-term contract being approximately 11 years, with the longest remaining contract term being 15 years.

Storage
Union Gas’ underground natural gas storage facilities have a working capacity of approximately 167 bcf in 25 underground facilities located in depleted gas fields. 100 PJs of the total working capacity is available to Union Gas for utility operations. Union Gas also has storage contracts with third parties for 11 bcf of storage capacity. Union Gas’ storage pools give customers access to all Dawn storage capacity and deliverability. Dawn's configuration provides flexibility for injections, withdrawals and cycling. Customers can purchase both firm and interruptible storage services at Dawn. Dawn offers customers a wide range of market choices and options with easy access to upstream and downstream markets. During 2018, Dawn provided storage, balancing, gas loans, transport, exchange and peaking services to over 195 counterparties.

A substantial amount of Union Gas’ storage revenue is generated by fixed annual demand charges, with the average length of a long-term contract being approximately four years, with the longest remaining contract term being 18 years.

NOVERCO
Noverco is a holding company that owns approximately 71% of Energir LP (Energir), formerly known as Gaz Metro Limited Partnership, a natural gas distribution company operating in the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in the Province of Quebec and the State of Vermont. Energir serves approximately 520,000 residential and industrial customers and is regulated by the Quebec Régie de l’énergie and the Vermont Public Utility Commission. Noverco also holds, directly and indirectly, an investment in our common shares. We own an equity interest in Noverco through ownership of 38.9% of its common shares and an investment in its preferred shares.

OTHER GAS DISTRIBUTION AND STORAGE

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Other Gas Distribution and Storage includes natural gas distribution utility operations in the Provinces of New Brunswick and Quebec.

Enbridge Gas New Brunswick Inc. operates the natural gas distribution franchise in the Province of New Brunswick, has approximately 12,000 customers and is regulated by the New Brunswick Energy and Utilities Board (NBEUB). On December 4, 2018, we announced a definitive agreement for the sale of Enbridge Gas New Brunswick Inc. Closing of the transaction remains subject to the receipt of regulatory approvals and other customary closing conditions and is expected to occur in 2019. For further information, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Asset Monetization.

We also wholly own Gazifère, a natural gas distribution company that serves approximately 40,000 customers in western Quebec, a market not served by Energir. Gazifère is regulated by the Quebec Régie de l’énergie.

COMPETITON
EGD and Union Gas’ distribution systems are regulated by the OEB and are subject to regulation in a number of areas, including rates. EGD and Union Gas are not generally subject to third-party competition within their distribution franchise area.

EGD and Union Gas compete with other forms of energy available to their 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, governmental regulations, the ability to convert to alternative fuels and other factors.

SUPPLY AND DEMAND
We expect that demand for natural gas in North America will continue to see low annual growth over the long term with continued growth in peak day demands. Some modest growth driven by low natural gas prices is expected to continue given the significant price advantage relative to their alternate energy options, with specific interest coming from communities that are not currently serviced by natural gas. EGD and Union Gas continue 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.

The storage and transportation marketplace continues to respond to changing natural gas supply dynamics including a robust supply environment. In recent years, the robust North American gas supply balance, due mainly to the development of shale gas volumes including the Alberta, British Columbia, Marcellus and Utica shale areas, has resulted in lower commodity prices and narrower seasonal price spreads. Unregulated storage values are primarily determined based on the difference in value between winter and summer natural gas prices. Storage values have been relatively stable to slightly rising as the North American natural gas supply and demand slowly returned to a more balanced position.

GREEN POWER & TRANSMISSION
Green Power and Transmission consists of investments in renewable energy assets and transmission facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United States primarily in the states of Colorado, Texas, Indiana and West Virginia. Green Power and Transmission also includes offshore wind facilities in operation and under development located in Europe.


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Green Power and Transmission includes interests in more than 1,700 MW of net renewable power generation capacity. Of this amount, approximately 477 MW is generated by wind facilities located in Canada, approximately 912 MW is generated by wind facilities located in the United States, approximately 100 MW is derived from a 24.9% interest in the 400 MW Rampion Offshore Wind Project and approximately 155 MW is derived from a 25% interest in the Hohe See Offshore wind power project and its subsequent expansion, both currently under construction. The vast majority of the power produced from these wind facilities is sold under long-term power purchase agreements. Green Power and Transmission also includes three solar facilities located in Ontario and a solar facility located in Nevada, with 51 MW and 27 MW, respectively, of power generating capacity net of our partners’ interests.

Green Power and Transmission also includes the Montana-Alberta Tie-Line, a 300 MW transmission line from Great Falls, Montana to Lethbridge, Alberta.

On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets, a 49% interest in two United States renewable assets and 49% of our interest in the Hohe See Offshore wind power project and its subsequent expansion, both currently under construction in Germany (collectively, the Renewable Assets). We maintain a 51% interest in the Renewable Assets and will continue to manage, operate and provide administrative services for these assets. For further information, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Asset Monetization.

COMPETITION
Our Green Power and Transmission assets operate in the North American and European power markets, which are subject to competition and the supply and demand balance for power in the provinces and states in which they operate. The vast majority of the revenue generated by currently operating assets is generated pursuant to long term power purchase agreements or has been substantially hedged. As such, the financial performance of these assets 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 market sector includes large utilities and small independent power producers, which are expected to aggressively compete for new project development opportunities and for the right to supply customers when contracts roll off.

SUPPLY AND DEMAND
The power generation and transmission network in North America is expected to undergo significant growth over the next 20 years. On the demand side, North American economic growth over the longer term is expected to drive growing electricity demand, although continued efficiency gains are expected to make the economy less energy-intensive and temper demand growth. On the supply side, legislation in Canada is expected to accelerate the retirement of aging coal-fired generation plants, resulting in a requirement for significant new generation capacity. While coal and nuclear facilities will continue to be core components of power generation in North America, gas-fired and renewable energy facilities, including biomass, hydro, solar and wind, are expected to be the preferred sources to replace coal-fired generation due to their lower carbon intensities.
 
In the United States, there is over 85 gigawatts (GW) of installed wind power capacity and in Canada over 12 GW of installed wind power capacity. Solar resources in southwestern states such as Arizona, California and Nevada are considered to be some of the best in the world for large-scale solar plants and the United States currently has over 35 GW of installed solar photovoltaic capacity. The United States passed legislation extending the availability of certain federal tax incentives which have supported the profitability of wind and solar projects. However, expanding renewable energy infrastructure in North America is not without challenges. Growing renewable generation capacity is expected to necessitate substantial capital investment to upgrade existing transmission systems or, in many cases, build new transmission lines, as these high quality wind and solar resources are often found in regions that are not

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in close proximity to markets. In the near-term, uncertainty over the availability of tax or other government incentives in various jurisdictions, the ability to secure long-term power purchase agreements through government or investor-owned power authorities and low market prices of electricity may hinder the pace of future new renewable capacity development. However, continued improvement in technology and manufacturing capacity in the past few years has reduced capital costs and improved yield factors associated with renewable energy generation. These positive developments are expected to render renewable energy more competitive and support ongoing investment over the long term.
 
In Europe, the future outlook for renewable energy, especially from offshore wind in countries with long coastlines and densely populated areas, is positive. According to the European Wind Energy Association, by 2030, wind energy capacity in Europe is expected to be 320 GW, including 66 GW of offshore capacity. There is also wide public support for carbon reduction targets and broader adoption of renewable generation across all governmental levels. Furthermore, governments in Europe are seeking to rationalize the contribution of nuclear power to the overall energy mix, which has resulted in an increased focus on alternative sources such as large scale offshore wind and is expected to create further investment opportunities.


ENERGY SERVICES

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

Through wholly-owned marketing subsidiaries, Energy Services provides crude oil, natural gas, NGL and power marketing services. Energy Services transact at many North American market hubs and provide our customers with various services, including transportation, storage, supply management and product exchanges. Our Energy Services subsidiaries are primarily physical commodity marketing companies focused on servicing customers across the value chain and capturing value from quality, time and location price differentials when opportunities arise. To execute these strategies, Energy Services transports and stores on both Enbridge-owned and third party assets using a combination of contracted long-term and short-term pipeline, storage tank, rail car and truck capacity agreements.

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

OPERATIONAL, ENVIRONMENTAL AND ECONOMIC REGULATION

LIQUIDS PIPELINES
Operational Regulation

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

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

PHMSA is designing an Integrity Verification Process intended to create standards to verify maximum allowable operating pressure, and to improve and expand integrity management processes. Additionally, PHMSA has established standards for storage facilities. There remains uncertainty as to how these standards will be implemented, but it is expected that the changes will impose additional costs on new pipeline projects as well as on existing operations. In this climate of increasingly stringent regulation, pipeline 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, earnings, cash flows and financial condition.

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

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

Environmental Regulation
We are also subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations generally require us to obtain and comply with a wide variety of environmental licenses, permits and other approvals.

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

In the United States, climate change action is evolving at state, regional and federal levels. The Supreme Court decision in Massachusetts v. Environmental Protection Agency in 2007 established that greenhouse gas (GHG) emissions were pollutants subject to regulation under the Clean Air Act. Pursuant to federal

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regulations, we are currently subject to an obligation to report our GHG emissions at our largest emitting facilities, but are not generally subject to limits on emissions of GHGs. In addition, a number of states have joined regional GHG initiatives, and a number are developing their own programs that would mandate reductions in GHG emissions. Public interest groups and regulatory agencies are increasingly focusing on the emission of methane associated with natural gas development and transmission as a source of GHG emissions. However, as the key details of future GHG restrictions and compliance mechanisms remain undefined, the likely future effects on our business are highly uncertain.

For its part, Canada has reaffirmed its strong preference for a harmonized approach with that of the United States. The Government of Canada has recently released the details of a federal system of carbon pricing starting in 2019. The pricing will apply to provinces and territories that are not in compliance with the federal requirements.

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

Economic Regulation
Our liquids pipelines also face economic regulation risk. Broadly defined, economic regulation risk is the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements including permits and regulatory approvals for new projects. The Canadian Mainline, Lakehead System and other liquids pipelines are subject to the actions of various regulators, including the NEB and FERC, with respect to the tariffs and tolls of those operations. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on our revenues and earnings. Delays in regulatory approvals on projects such as our L3R Program, could result in cost escalations and construction delays, which also negatively impact our operations.

GAS TRANSMISSION & MIDSTREAM
Operational Regulation
The span of regulation risks that apply to the Liquids Pipeline business as described above under Liquids Pipelines also applies to the Gas Transmission and Midstream business. Additionally, most of our United States gas transmission operations are regulated by the FERC. The FERC regulates natural gas transmission in United States interstate commerce including the establishment of rates for services. The FERC also regulates the construction of United States interstate natural gas pipelines and storage facilities, including the extension, enlargement and abandonment of facilities. In addition, certain operations are subject to oversight by state regulatory commissions. To the extent that the natural gas intrastate pipelines that transport or store natural gas in interstate commerce provide services under Section 311 of the Natural Gas Policy Act of 1978, they are subject to FERC regulations. The FERC may propose and implement new rules and regulations affecting interstate natural gas transmission and storage companies, which remain subject to the FERC’s jurisdiction. These initiatives may also affect certain transmission of gas by intrastate pipelines.

Our operations are subject to the jurisdiction of the Environmental Protection Agency and various other federal, state and local environmental agencies. Our United States interstate natural gas pipelines and certain of DCP Midstream’s gathering and transmission pipelines are also subject to the regulations of the DOT concerning pipeline safety.

The intrastate natural gas and NGL pipelines owned by us and DCP Midstream are subject to state regulation. The natural gas gathering and processing activities of DCP Midstream are not subject to FERC regulation.


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Our Canadian operations are governed by various federal and provincial agencies with respect to pipeline safety, including the NEB, the Transportation Safety Board and the Ontario Technical Standards and Safety Authority.

Our Canadian natural gas transmission and distribution operations and approximately two-thirds of the storage operations in Canada are subject to regulation by the NEB or the provincial agencies in Canada, such as the OEB. These agencies have jurisdiction similar to the FERC for regulating rates, the terms and conditions of service, the construction of additional facilities and acquisitions. Our British Columbia Pipeline currently has a two year Settlement Agreement with its Shippers that provides for cost sharing on certain controllable expenses and sets out the regulated ROE for the two year period. The Settlement Agreement has been approved by the NEB.

Our British Columbia Field Services business in western Canada is regulated by the NEB pursuant to a framework for light-handed regulation under which the NEB acts on a complaints-basis for rates associated with that business.

GAS DISTRIBUTION
Operational Regulation
Our gas distribution utility operations are regulated by the OEB, the Quebec Régie de l’énergie and the NBEUB, among others. Regulators’ future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which we operate. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position, or that would have been recorded on the Consolidated Statements of Financial Position in absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded.

We seek to mitigate operational regulation risk. We retain dedicated professional staff and maintain strong relationships with customers, intervenors and regulators. This strong regulatory relationship continued in 2018 with the OEB’s decision to approve of the application to amalgamate EGD and Union Gas in accordance with the OEB's guidance for Mergers, Acquisitions, Amalgamations and Divestitures. The decision approved a rate setting mechanism, effective January 1, 2019, to be employed during a five-year deferred rebasing period from 2019 through 2023, and allows us the opportunity to drive efficiencies and synergies.

Enbridge Gas Distribution
EGD’s distribution rates, beginning in 2014 through 2018, were set under a five-year customized incentive regulation (IR) plan.  The plan required EGD to update select items each year beginning in 2015 and through 2018, in order to establish final allowed revenues and rates. Under the customized IR plan, EGD shared equally with customers, earnings above the approved allowed ROE. EGD's after-tax ROE was 9.00% for 2018 and 8.78% for 2017.

Union Gas
Union Gas’ distribution rates, beginning in 2014 through 2018, were set under a five-year IR plan which established new rates at the beginning of each year through the use of a pricing formula, rather than through the examination of revenue and cost forecasts. The IR plan included an earnings sharing mechanism with customers that permitted Union Gas to fully retain the ROE from utility operations up to 9.93%, to retain 50% of any earnings between 9.93% and 10.93%, and to retain 10% of any earnings above 10.93%.

Environmental Regulation
Our workers, operations and facilities are subject to municipal, provincial and federal legislation which regulate the protection of the environment and the health and safety of workers. Environmental legislation primarily includes regulation of discharges to air, land and water; management and disposal of hazardous waste; and the assessment and management of contaminated sites.

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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 spills or emissions in excess of permitted levels. These events could result in injuries to workers or the public, fines, orders or charges, adverse impacts to the environment in which we operate, and/or property damage. We could also incur future liability for environmental (soil and groundwater) contamination associated with past and present site activities.

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

The gas distribution system and our other operations must maintain a number of environmental approvals and permits from governmental authorities to operate. As a result, these assets and facilities are subject to periodic inspection. An Annual Written Summary Report is submitted to the Ontario Ministry of Environment, Conservation and Parks (MECP), formerly the Ministry of Environment and Climate Change to demonstrate we are in good standing with our Environmental Compliance Approvals. Failure to maintain regulatory compliance could result in operational interruptions, fines, and/or orders for additional pollution control technology or environmental mitigation. As environmental requirements and regulations become more stringent, the cost to maintain compliance and the time required to obtain approvals has increased.

On July 3, 2018, the Government of Ontario issued Ontario Regulation 386/18 (the “Regulation”) which revoked the Cap and Trade program regulation and prohibits registered participants from purchasing, selling, trading or otherwise dealing with emission allowances or credits. On July 25, 2018, the Government of Ontario introduced Bill 4 to wind down the Cap and Trade program. On October 31, 2018, Bill 4, Cap and Trade Cancellation Act, 2018 (the “Act”) received Royal Assent. This Act detailed the wind down of the Ontario Cap and Trade program, effectively expunging any compliance obligation associated with greenhouse gas emissions.

Additionally, in October 2018, the federal government confirmed that Ontario will be subject to the federal government’s carbon pricing program (otherwise known as the Federal Carbon Pricing Backstop Program) (the Program). EGD and Union Gas are in the process of updating already filed rate applications for the Program, based on recent regulation updates, with the OEB. We anticipate that all costs associated with the Program, including implementation and ongoing sustainment, will be considered a pass-through cost.

As with previous years, in 2018, the EGD and Union Gas each reported GHG emissions to the Ontario MECP, and a number of voluntary reporting programs. Emissions from Ontario combustion sources were verified in detail by a third party accredited verifier with no material discrepancies found. Additionally, operational emissions from venting, fugitive and natural gas distribution emissions were reported to the MECP starting in 2017 in accordance with O. Reg. 143/16 - Quantification, Reporting, and Verification of Greenhouse Gas Emissions Regulation standard quantification methods ON.350 and ON.400, respectively.

EGD and Union Gas utilize emissions data management processes and systems to help with the data capture and mandatory and voluntary reporting needs. Quantification methodologies and emission factors will continually be updated in the system as required. Each utility publicly reports its GHG emissions. Collectively, EGD and Union Gas continue to work with industry associations to refine quantification methodologies and emissions factors, as well as best management practices to minimize emissions.


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EMPLOYEES

We had approximately 12,000 employees as at December 31, 2018, including approximately 8,500 employees in Canada and approximately 3,500 employees in the United States. Approximately 1,800 of our employees are subject to collective bargaining agreements governing their employment with us. Approximately 48% of those employees are covered under agreements that either have expired or will expire by December 31, 2019. We are currently in the process of collective bargaining with respect to the expired or expiring contracts. We have mature working relationships with our labor unions and the parties have traditionally committed themselves to the achievement of renewal agreements without a work stoppage.

EXECUTIVES AND OTHER OFFICERS

The following table sets forth information regarding our executive and other officers.
Name
Age
Position
Al Monaco
59
President & Chief Executive Officer
John K. Whelen
59
Executive Vice President & Chief Financial Officer
Cynthia L. Hansen
54
Executive Vice President & President, Utilities and Power Operations
D. Guy Jarvis
55
Executive Vice President & President, Liquids Pipelines
Byron C. Neiles
53
Executive Vice President, Corporate Services
Robert R. Rooney
62
Executive Vice President & Chief Legal Officer
William T. Yardley
54
Executive Vice President & President, Gas Transmission and Midstream
Vern D. Yu
52
Executive Vice President & Chief Development Officer
Allen C. Capps
48
Senior Vice President & Chief Accounting Officer

Al Monaco was appointed President and Chief Executive Officer on October 1, 2012. He is also a member of the Enbridge Board of Directors. Prior to being appointed President of Enbridge, Mr. Monaco served as President, Gas Pipelines, Green Energy & International with responsibility for the growth and operations of our gas pipelines, including the gas gathering and processing operations in the United States, our gulf coast offshore assets and our investments in Alliance, Vector and Aux Sable, as well as our International business development and investment activities and Green Energy.

John K. Whelen was appointed Executive Vice President and Chief Financial Officer of Enbridge on October 15, 2014. Previously our Senior Vice President and Controller, Mr. Whelen retained executive leadership for our financial reporting function, while assuming responsibility for our tax and treasury functions. Prior to that, Mr. Whelen served as Senior Vice President Corporate Development and Vice President & Treasurer. Mr. Whelen has been part of the Enbridge team since 1992 holding a number of leadership positions of increasing responsibility within the Finance function.

Cynthia L. Hansen was appointed Executive Vice President and President, Utilities and Power Operations, on February 27, 2017. Ms. Hansen is responsible for the overall leadership and operations of EGD and Union Gas, as well as Enbridge Gas New Brunswick Inc. and Gazifère. She also holds responsibility for the operations of our power generating assets, which currently include renewable energy investments in wind, solar, geothermal and hydroelectric, as well as waste heat recovery facilities and power transmission lines owned in whole or in part by us.

D. Guy Jarvis was appointed Executive Vice President and President, Liquids Pipelines on February 27, 2017. Mr. Jarvis has been President of our Liquids Pipelines group since March 1, 2014, with responsibility for all of our crude oil and liquids pipeline businesses across North America. Mr. Jarvis

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previously held the title of Chief Commercial Officer for Liquids Pipelines, with responsibility for strategic and integrated services, customer service, finance, and business and market development. Prior to Mr. Jarvis' work in Liquids Pipelines, he served as President, Gas Distribution, providing overall leadership to EGD, as well as Enbridge Gas New Brunswick Inc. and Gazifère.

Byron C. Neiles was appointed Executive Vice President, Corporate Services on May 2, 2016. Mr. Neiles has oversight of our centralized capital and maintenance projects division, as well as Information Technology, Human Resources, Real Estate & Workplace Services, Supply Chain Management, and Safety, Environment, Land & Right-of-Way groups. Mr. Neiles had previously held the role of Senior Vice President, Major Projects, Enterprise Safety and Operational Reliability, and had been Senior Vice President of Major Projects since November 2011, after joining our Major Projects group in April 2008.

Robert R. Rooney was appointed Executive Vice President and Chief Legal Officer on February 1, 2017. Mr. Rooney leads our legal team across the organization and oversees our Public Affairs and Communications (including Corporate Social Responsibility).

William T. Yardley was named Executive Vice President and President, Gas Transmission and Midstream on February 27, 2017 coincident with the closing of the Merger Transaction. Mr. Yardley is also the President of SEP. Prior to the closing of the Sponsored Vehicle buy-ins, Mr. Yardley was also the Chairman of the Board of SEP; he now continues to serve as a Manager on the Board of Managers. Mr. Yardley, based in Houston, was previously President of Spectra Energy’s United States Transmission and Storage business, leading the business development, project execution, operations and environment, health and safety efforts associated with Spectra Energy’s United States portfolio of assets.

Vern D. Yu was appointed Executive Vice President and Chief Development Officer on May 2, 2016. Mr. Yu leads our Corporate Development team, responsible for the identification and execution of value enhancing growth opportunities and managing capital allocation and Enbridge’s portfolio mix. Mr. Yu also provides executive oversight to our Energy Services group, Tidal Energy. Previously, Mr. Yu served as Senior Vice President, Corporate Planning and Chief Development Officer. He has been the lead of our Corporate Development team since July 1, 2014.

Allen C. Capps is the Senior Vice President and Chief Accounting Officer of Enbridge. Mr. Capps is responsible for our accounting operations and financial reporting functions, including internal and external financial reporting. Prior to assuming his current role on February 27, 2017, in connection with the closing of the Merger Transaction, Mr. Capps served as Vice President and Controller of Spectra Energy, where he was responsible for the financial accounting and reporting functions.

ADDITIONAL INFORMATION

Additional information about us is available on our website at www.enbridge.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. The aforementioned information is made available in accordance with legal requirements and is not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K. We make available free of charge, through our website, annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as well as proxy statements, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Reports, proxy statements and other information filed with the SEC may also be obtained through the SEC’s website (www.sec.gov).

ENBRIDGE GAS DISTRIBUTION INC. AND UNION GAS LIMITED
Additional information about EGD and Union Gas can be found in their combined annual information form, financial statements and management's discussion and analysis (MD&A) for the year ended December 31, 2018 which have been filed with the securities commissions or similar authorities in each

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of the provinces of Canada. These documents contain detailed disclosure with respect to EGD and Union Gas and are publicly available on SEDAR at www.sedar.com under the continuing amalgamated company Enbridge Gas Inc. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

ENBRIDGE PIPELINES INC.
Additional information about EPI can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2018 which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to EPI and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

WESTCOAST ENERGY INC.
Additional information about Westcoast Energy Inc. can be found in its annual information form, financial statements and MD&A for the year ended December 31, 2018 which have been filed with the securities commissions or similar authorities in each of the provinces of Canada. These documents contain detailed disclosure with respect to Westcoast Energy Inc. and are publicly available on SEDAR at www.sedar.com. These documents are not, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.

DCP MIDSTREAM LP
Additional information about DCP Midstream can be found in its Annual Report on Form 10-K that will be filed with the SEC. This document contains detailed disclosure with respect to DCP Midstream, and will be publicly available on EDGAR at www.sec.gov. No part of the Form 10-K filed by DCP Midstream is, unless otherwise specifically stated, incorporated by reference into this Annual Report on Form 10-K.



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ITEM 1A. RISK FACTORS

Execution of our capital projects subjects us to various regulatory, development, operational and market risks that may affect our financial results.

Our ability to successfully execute the development of our organic growth projects is subject to various regulatory, development, operational and market risks, including:
the ability to obtain necessary approvals and permits from governments and regulatory agencies on a timely basis and on acceptable terms and to maintain those issued approvals and permits and satisfy the terms and conditions imposed therein;
potential changes in federal, state, provincial and local statutes and regulations, including environmental requirements, that may prevent a project from proceeding or increase the anticipated cost of the project;
impediments on our ability to acquire or renew rights-of-way or land rights on a timely basis and on acceptable terms;
opposition to our projects by third parties, including special interest groups;
the availability of skilled labor, equipment and materials to complete projects;
the ability to construct projects within anticipated costs, including the risk of cost overruns resulting from inflation or increased costs of equipment, materials or labor, contractor or supplier non-performance, weather, geologic conditions or other factors beyond our control, that may be material;
general economic factors that affect the demand for our projects; and
the ability to raise financing for these capital projects.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated cost. Recent projects that have experienced delays include the U.S. L3R Program, Atlantic Bridge and the T-South Expansion. New projects may not achieve their expected investment return, which could affect our financial results, and hinder our ability to secure future projects. For additional discussion of specific proceedings that could affect our operations and financial results, refer to Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates.

Cyber-attacks or security breaches could adversely affect our business, operations or financial results.

Our business is dependent upon information systems and other digital technologies for controlling our plants and pipelines, processing transactions and summarizing and reporting results of operations. The secure processing, maintenance and transmission of information is critical to our operations. A security breach of our network or systems, or the network or systems of our third-party vendors, could result in improper operation of our assets, potentially including delays in the delivery or availability of our customers’ products, contamination or degradation of the products we transport, store or distribute, or releases of hydrocarbon products for which we could be held liable. Furthermore, we and our third-party vendors collect and store sensitive data in the ordinary course of our business, including personal identification information of our employees as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. We have a cyber-security controls framework in place which has been derived from the National Institute of Standards and Technology Cyber-security Framework and International Organization for Standardization 27001 standards. We monitor our control effectiveness in an increasing threat landscape and continuously take action to improve our security posture. We have implemented a 7X24 security operations center to monitor, detect and investigate any anomalous activity in our network together with an incident response process that we test on a monthly basis. We conduct independent cyber-security audits and penetration tests on a regular basis to test that our preventative and detective controls are working as designed. Despite our security measures, our information systems, or those of our vendors, may become the target of cyber-attacks (including hacking, viruses or acts of terrorism) or security breaches (including employee error, malfeasance or other

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breaches), which could compromise our network or systems, or those of our vendors, and result in the release or loss of the information stored therein, misappropriation of assets, disruption to our operations or damage to our facilities. Our current insurance coverage programs do not contain specific coverage for cyber-attacks or security breaches. As a result of a cyber-attack or security breach, we could also be liable under laws that protect the privacy of personal information, subject to regulatory penalties, experience damage to our reputation or a loss of consumer confidence in our products and services, or incur additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could adversely affect our business, operations or financial results.

Our operations involve safety risks to the public and to our workers and contractors.

Several of our pipelines and distribution systems and related assets are operated in close proximity to populated areas and a major incident could result in injury to members of the public. In addition, given the natural hazards inherent in our operations, our workers and contractors are subject to personal safety risks. A public safety incident or an injury to our workers or contractors could result in reputational damage to us, material repair costs or increased costs of operating and insuring our assets.

Changes in our reputation with stakeholders, special interest groups, political leadership, the media or other entities could have negative impacts on our business, operations or financial results.

There could be negative impacts on our business, operations or financial results due to changes in our reputation with stakeholders, special interest groups (including non-governmental organizations), political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups’ negative portrayal of the industry in which we operate as well as their opposition to development projects, such as the Bakken Pipeline System. Potential impacts of a negative public opinion may include:
loss of business;
loss of ability to secure growth opportunities;
delays in project execution;
legal action;
increased regulatory oversight or delays in regulatory approval; and
loss of ability to hire and retain top talent.

We are also exposed to the risk of higher costs, delays or even project cancellations due to increasing pressure on governments and regulators by special interest groups. Recent judicial decisions have increased the ability of special interest groups to make claims and oppose projects in regulatory and legal forums. In addition to issues raised by groups focused on particular project impacts, we and others in the energy and pipeline businesses are facing opposition from organizations opposed to oil sands development and shipment of production from oil sands regions.

Pipeline operations involve numerous risks that may adversely affect our business and financial results.

Operation of complex pipeline systems, gathering, treating, storing and processing operations involves many risks, hazards and uncertainties. These events include adverse weather conditions, accidents, the breakdown or failure of equipment or processes, the performance of the facilities below expected levels of capacity and efficiency and catastrophic events such as explosions, fires, earthquakes, hurricanes, floods, landslides or other similar events beyond our control. These types of catastrophic events could result in loss of human life, significant damage to property, environmental pollution and impairment of our operations, any of which could also result in substantial losses for which insurance may not be sufficient or available and for which we may bear a part or all of the cost. We have experienced such events in the past, including in 2010 on Lines 6A and 6B of the Lakehead System, in October 2018 at the BC Pipeline

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T-South system and in January 2019 at the Texas Eastern pipeline, and cannot guarantee that we will not experience catastrophic events in the future. In addition, we could be subject to significant fines and penalties from regulators in connection with any such events. Environmental incidents could also lead to an increased cost of operating and insuring our assets, thereby negatively impacting earnings. An environmental incident could have lasting reputational impacts to us and could impact our ability to work with various stakeholders. For pipeline and storage assets located near populated areas, including residential communities, commercial business centers, industrial sites and other public gathering locations, the level of damage resulting from these catastrophic events could be greater.

There are utilization risks in respect to our assets.

In respect to our Liquids Pipeline assets, we are exposed to throughput risk under the CTS on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect our revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of our assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions outside of our control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on our pipelines.

In respect to our Gas Transmission and Midstream assets, gas supply and demand dynamics continue to change as a result of the development of non-conventional shale gas supplies. The increase in natural gas supply has resulted in declines in the price of natural gas in North America. As a result, a shift occurred to extraction of gas in richer, wet gas areas with higher NGL content which depressed activity in dry fields. This, in turn, has contributed to a resulting oversupply of pipeline takeaway capacity in some areas, which can adversely affect our revenues and earnings.

In respect to our Gas Distribution assets, customers are billed on a combination of both fixed charge and volumetric basis and our ability to collect their respective total revenue requirement (the cost of providing service, including a reasonable return to the utility) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of 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. Our Gas Distribution business has deferral accounts approved by the OEB that provide regulatory protection against the margin impacts associated with declining annual average consumption due to efficiencies and customers’ conservation efforts. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Even in those circumstances where 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.

In respect to our Green Power and Transmission assets, earnings from these assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Green Power and Transmission projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at any

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of the Green Power and Transmission facilities could lead to decreased earnings and cash flows for us. Additionally, inefficiencies or interruptions of Green Power and Transmission facilities due to operational disturbances or outages resulting from weather conditions or other factors, could also impact earnings.

Power produced from Green Power and Transmission assets is also often sold to a single counterparty under power purchase agreements or other long-term pricing arrangements. In this respect, the performance of the Green Power and Transmission assets is dependent on each counterparty performing its contractual obligations under the power purchase agreements or pricing arrangement applicable to it.

Our transformation projects may fail to fully deliver anticipated results.

We launched projects starting in 2016 to transform various processes, capabilities and reporting systems infrastructure to continuously improve effectiveness and efficiency across the organization and are subject to transformation project risk with respect to these projects. Such projects, some of which will continue into 2019 and 2020, including integration initiatives arising out of the Merger Transaction and the amalgamation of EGD and Union Gas, are subject to transformation project risk. Transformation project risk is the risk that modernization projects carried out by us and our subsidiaries do not fully deliver anticipated results due to insufficiently addressing the risks associated with project execution and change management. This could result in negative financial, operational and reputational impacts.

A service interruption could have a significant impact on our operations, and negatively impact financial results, relationships with stakeholders and our reputation.

A service interruption due to a major power disruption or curtailment of commodity supply could have a significant impact on our operations and negatively impact financial results, relationships with stakeholders and our reputation. Specifically, for Gas Distribution, any prolonged interruptions would ultimately impact gas distribution customers. Service interruptions that impact our crude oil 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.

Our assets vary in age and were constructed over many decades which may cause our inspection, maintenance or repair costs to increase in the future.

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

An impairment of our assets, including goodwill, property, plant, and equipment, intangible assets, and/or equity method investments, could reduce our earnings.

GAAP requires us to test certain assets for impairment on either an annual basis or when events or circumstances occur which indicate that the carrying value of such assets might be impaired. The outcome of such testing could result in impairments of our assets including our goodwill, property, plant and equipment, intangible assets, and/or equity method investments. Additionally, any asset monetizations could result in impairments if such assets are sold or otherwise exchanged for amounts less than their carrying value. If we determine that an impairment has occurred, we would be required to take an immediate noncash charge to earnings.

We rely on access to short-term and long-term capital markets to finance capital requirements and support liquidity needs, and cost effective access to those markets can be affected, particularly if we or our rated subsidiaries are unable to maintain an investment-grade credit rating.


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

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

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

Our forecasted assumptions may not materialize as expected on our expansion projects, acquisitions and divestitures.

We evaluate expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, change in cost estimates, project scoping and risk assessment could result in a loss in our profits.

We may not be able to sell assets or, if we are able to sell assets, to raise an optimal amount of capital from such asset sales. In addition, the timing to close asset sales could be significantly different than our expected timeline.

We have monetized or are in the process of monetizing certain assets to execute on our strategic priority to focus on core assets and to accelerate debt reduction and provide capital. Of the $7.8 billion in announced assets sales, $5.7 billion have closed. The remaining $2.1 billion is still subject to regulatory approvals and other factors. If we are able to sell assets, the timing of the receipt of the asset sale proceeds may not align with the timing of our capital requirements. A failure to close remaining sales or a misalignment of the timing of capital raised and capital funding needs could have an adverse impact on our business, financial condition, results of operations, and cash flows.

Our operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.


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Many of our operations are regulated. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States have changed significantly in past years and further substantial changes may occur.

On February 8, 2018, the Government of Canada introduced legislation to revise the process for assessing major resource projects. If the legislation is passed in its current form, we believe it would have adverse impacts on pipeline companies, particularly in relation to the regulatory review process for proposed new projects that are “designated projects”, by making overall timelines for the development and execution of these projects longer and significantly increasing uncertainty.

Compliance with legislative changes may impose additional costs on new pipeline projects as well as on existing operations. Failure to comply with applicable regulations could result in a number of consequences which may have an adverse effect on our operations, earnings, financial condition and cash flows.

Our operations are subject to operational regulation and failure to comply with applicable regulations could have a negative impact on our business, financial condition or results of operations.

Operational regulation risks relate to compliance with applicable operational rules and regulations mandated by governments or applicable regulatory authorities, breaches of which could result in fines, penalties, operating restrictions and an overall increase in operating and compliance costs. Regulatory scrutiny over the integrity of our assets and operations has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on our future earnings and the cost related to the construction of new projects. Regulators' future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which we operate. We seek to mitigate operational regulation risk by active monitoring and consulting on potential regulatory requirement changes with the respective regulators directly, or through industry associations. We also develop robust response plans to regulatory changes or enforcement actions. While we believe the safe and reliable operation of our assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators to make unilateral decisions that could have a financial impact on us.

Our operations are subject to economic regulation and failure to secure regulatory approval for our proposed or existing project could have a negative impact on our business, financial condition or results of operations.

Our liquids pipelines face economic regulatory risk, the risk that governments or regulatory agencies change or reject proposed or existing commercial arrangements including permits and regulatory approvals for new projects. We believe that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of our liquids pipeline assets. We also involve our legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations as well as in the establishment of tariffs and tolls on new and existing pipelines. However, despite our efforts to mitigate economic regulation risk, there remains a risk that a regulator could modify significantly its own long-standing policies for rate making as well as overturn long-term agreements that we have entered into with shippers or deny the approval and permits for new projects.

Our operations are subject to numerous environmental laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans, or expose us to environmental liabilities.

We are subject to numerous environmental laws and regulations affecting many aspects of our present and future operations, including air emissions, water quality, wastewater discharges, solid waste and hazardous waste.

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Failure to comply with environmental laws and regulations and failure to secure permits necessary for our operations may result in the imposition of fines, penalties and injunctive measures affecting our operating assets. In addition, changes in environmental laws and regulations or the enactment of new environmental laws or regulations could result in a material increase in our cost of compliance with such laws and regulations. We may not be able to obtain or maintain all required environmental regulatory approvals and permits for our operating assets or development projects. If there is a delay in obtaining any required environmental regulatory approvals or permits, if we fail to obtain or comply with them, or if environmental laws or regulations change or are administered in a more stringent manner, the operations of facilities or the development of new facilities could be prevented, delayed or become subject to additional costs. We expect that costs we incur to comply with environmental regulations in the future may have a significant effect on our earnings and cash flows.

Our insurance coverage may not be sufficient to cover our losses in the event of an accident, natural disaster or other hazardous event.

Our operations are subject to many hazards inherent in our industry. Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We maintain a comprehensive insurance program for us, our subsidiaries and certain of our affiliates. This program includes insurance coverage in types and amounts and with terms and conditions that are generally consistent with coverage customary for our industry.

Although we believe our current coverage is adequate for our purposes, we have in the past had occurrences that led to losses exceeding our then-applicable coverage limits, and there is no assurance that the same may not happen in the future. In the unlikely event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among our entities on an equitable basis based on an insurance allocation agreement among us and our subsidiaries.

Competition may result in a reduction in demand for our services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected.

We face competition from competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada, the United States and internationally and from proposed pipelines that seek to access markets currently served by our liquids pipelines. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. We also face competition from alternative gathering and storage facilities. Our natural gas transmission and storage businesses compete with similar facilities that serve our supply and market areas in the transmission and storage of natural gas. The natural gas transported in our business competes with other forms of energy available to our customers and end-users, including electricity, coal, propane, fuel oils, and renewable energy. 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.

We are exposed to the credit risk of our customers.

We are exposed to the credit risk of our customers in the ordinary course of our business. Generally, our customers are rated investment-grade, are otherwise considered creditworthy or provide us security to satisfy credit concerns. A significant amount of our credit exposures for transmission, storage, and gathering and processing services are with customers who have an investment-grade rating (or the equivalent based on our evaluation) or are secured by collateral. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including possible declines in our customers’ creditworthiness. As a result of future capital projects for which natural gas and

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oil producers may be the primary customer, our credit exposure with below investment-grade customers may increase. It is possible that customer payment defaults, if significant, could adversely affect our earnings and cash flows.

Our business requires the retention and recruitment of a skilled workforce, and difficulties recruiting and retaining our workforce could result in a failure to implement our business plans.

Our operations and management require the retention and recruitment of a skilled workforce, including engineers, technical personnel and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. If we are unable to retain current employees and/or recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased allocated costs to retain and recruit these professionals.

We are involved in numerous legal proceedings, the outcomes of which are uncertain, and resolutions adverse to us could adversely affect our financial results.

We are subject to numerous legal proceedings. Litigation is subject to many uncertainties, and we cannot predict the outcome of individual matters with assurance. It is reasonably possible that the final resolution of some of the matters in which we are involved could require additional expenditures, in excess of established reserves, over an extended period of time and in a range of amounts that could adversely affect our financial results. 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 legal proceedings.

Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war, and other civil unrest or activism could adversely affect our business, operations or financial results.

Terrorist attacks and threats, escalation of military activity or acts of war, or other civil unrest or activism may have significant effects on general economic conditions 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 United States, or Canada, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targets in the United States and Canada. In addition, increased environmental activism against pipeline construction and operation could potentially result in work delays, reduced demand for our products and services, increased legislation or denial or delay of permits and rights-of-way. Finally, the disruption or a significant increase in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could adversely affect our business, operations or financial results.

Our Liquids Pipelines growth rate and results may be indirectly affected by commodity prices and Government policy.

Recent efforts by the Alberta Government to manage supply and inventories in Western Canada is expected to be short term in application and have negligible impact on mainline throughput, as enough inventory exists to meet refinery customer needs and service our favorable markets. Current oil sands production is very robust and is expected to grow in the future as producers actively improve the competitiveness of their existing projects. Sanctioned projects due to come on stream in the next 24 months, which may face delays under the Alberta curtailment program, are not as sensitive to short-term declines in crude oil prices, as investment commitments have already been made. 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

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

Our Gas Transmission and Midstream results may be adversely affected by commodity price volatility and risks associated with our hedging activities.

Our exposure to commodity price volatility is inherent to part of our natural gas processing business. We employ a disciplined hedging program to manage this direct commodity price risk. Because we are not fully hedged, we may be adversely impacted by commodity price exposure on the commodities we receive in-kind as payment for our gathering, processing, treating and transportation services. As a result of our unhedged exposure and the pricing of our hedge positions, a substantial decline in the prices of these commodities could adversely affect our financial results.

Additionally, our hedging activities may not be as effective as we intend in reducing the volatility of our cash flows. To the extent that we engage in hedging activities to reduce our commodity price exposure, we likely will be prevented from realizing the full benefits of price increases above the level of the hedges. Our hedging activities can result in substantial losses if hedging arrangements are imperfect or ineffective and our hedging policies and procedures are not followed properly or do not work as intended. Further, hedging contracts are subject to the credit risk that the other party may prove unable or unwilling to perform its obligations under the contracts, particularly during periods of weak and volatile economic conditions. In addition, certain of the financial instruments we use to hedge our commodity risk exposures must be accounted for on a mark-to-market basis. This causes periodic earnings volatility due to fluctuations in commodity prices.

Our Energy Services results may be adversely affected by commodity price volatility.

Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Volatility in commodity prices due to changing market conditions could limit margin opportunities and impede Energy Services' ability to cover capacity commitments. Furthermore, commodity prices could have negative earnings and cash flow impacts if the cost of the commodity is greater than resale prices achieved by us.

Our risk management policies cannot eliminate all risks. In addition, any non-compliance with our risk management policies could adversely affect our business, operations or financial results.

We use derivative financial instruments to manage the risks associated with movements in foreign exchange rates, interest rates, commodity prices and our share price to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are associated with an underlying asset, liability and/or forecasted transaction. We do not enter into transactions with the objective of speculating on commodity prices or interest rates. These policies cannot, however, eliminate all risk of unauthorized trading and other speculative activity. Although this activity is monitored independently by our risk management function, we remain exposed to the risk of non-compliance with our risk management policies. We can provide no assurance that our risk management function will detect and prevent all unauthorized trading and other violations of our risk management policies and procedures, particularly if deception, collusion or other intentional misconduct is involved, and any such violations could adversely affect our business, operations or financial results.


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The effects of United States Government policies on trade relations between Canada and the United States are uncertain.

The new United States-Mexico-Canada Agreement (USMCA) (in Canada, known as the Canada-United States-Mexico Agreement (CUSMA)) is intended to supersede the North American Free Trade Agreement (NAFTA). USMCA/CUSMA has been signed but not ratified by the legislature of each of the United States, Canada and Mexico. NAFTA provides protection against tariffs, duties and other charges or fees and assures access by the signatories. The impact of USMCA/CUSMA, if ratified, on energy markets is uncertain.

The effect of comprehensive United States tax reform legislation on us, whether adverse or favorable, is uncertain.

On December 22, 2017, President Trump signed into law H.R. 1, “An Act to provide for reconciliation pursuant to titles II and V of the concurrent resolution on the budget for fiscal year 2018” (informally titled the Tax Cuts and Jobs Act). The effect of the Tax Cuts and Jobs Act on us, our subsidiaries and our shareholders, whether adverse or favorable, is still uncertain. While the United States Treasury issued substantial guidance in 2018 in the form of proposed regulations, uncertainty will still exist until the proposed regulations are finalized.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

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

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

Titles to our properties acquired in our liquids and natural gas systems are subject to encumbrances in some cases. We believe that none of these burdens should materially detract from the value of these properties or materially interfere with their use in the operation of our business.

ITEM 3. LEGAL PROCEEDINGS

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


47


ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

48


PART II

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

Common Stock
Our common stock is traded on the TSX and NYSE under the symbol “ENB.” As at February 8, 2019, there were approximately 2,022,657,570 holders of record of our common stock. A substantially greater number of holders of our common stock are "street name" or beneficial holders, whose shares are held by banks, brokers and other financial institutions.

Dividends
The following table indicates the dividends paid per common share (in Canadian dollars):
 
2018

2017

Q1
0.671

0.583

Q2
0.671

0.610

Q3
0.671

0.610

Q4
0.671

0.610

Consistent with our objective of delivering annual cash dividend increases, we announced a quarterly dividend of $0.738 per common share payable on March 1, 2019, which represents a 10 percent increase from the prior quarterly rate. We expect to continue our policy of paying regular cash dividends. The declaration and payment of dividends are subject to the sole discretion of our Board of Directors and will depend upon many factors, including the financial condition, earnings and capital requirements of our operating subsidiaries, covenants associated with certain debt obligations, legal requirements, regulatory constraints and other factors deemed relevant by our Board of Directors.
Securities Authorized for Issuance Under Equity Compensation Plans
Information in response to this item is incorporated by reference from our Proxy Statement to be filed with the SEC relating to our 2019 annual meeting of shareholders.
Recent Sales of Unregistered Equity Securities
On December 11, 2017, we issued 20,000,000 of Series 19 Preference Shares in Canada pursuant to a prospectus supplement to our Canadian base shelf prospectus in reliance on Regulation S. Please refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Preference Share Issuances for further discussion of the transaction.

On November 29, 2017, we entered into a private placement for common shares with three institutional investors. The issuance price was $44.84, with gross proceeds of $1.5 billion. We issued 33,456,003 common shares in reliance on Rule 506(b) of Regulation S. The proceeds were used to pay down short-term indebtedness pending reinvestment in capital projects.

Issuer Purchases of Equity Securities
None.

Total Shareholder Return
The following graph reflects the comparative changes in the value from January 1, 2014 through December 31, 2018 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 United States peer group (comprising D, DTE, ET, EPD, KMI, MMP, NI, OKE, PCG, PAA, SRE and WMB) and (5) our Canadian peer group (comprising

49


CU, FTS, IPL, PPL and TRP). The amounts included in the table were calculated assuming the reinvestment of dividends at the time dividends were paid.
totalshareholderreturn.jpg
 
January 1,
2014
December 31,
 
2014

2015

2016

2017

2018

Enbridge Inc.
100.00

132.30

105.29

134.79

122.93

112.74

S&P/TSX Composite
100.00

110.55

101.36

122.73

133.89

121.99

S&P 500 Index
100.00

113.69

115.26

129.05

157.22

150.33

United States Peers1
100.00

123.29

93.64

122.09

123.03

114.49

Canadian Peers
100.00

127.12

102.14

133.43

142.98

129.44

1 For the purpose of the graph, it was assumed that CAD:USD conversion ratio remained at 1:1 for the years presented.

50


ITEM 6. SELECTED FINANCIAL DATA
The following selected financial data should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.
 
Years Ended December 31,
 
20181

20171

20161

2015

2014

(millions of Canadian dollars, except per share amounts)
 



 
Consolidated Statements of Earnings
 
 
 
 
 
Operating revenues

$46,378

$
44,378

$
34,560

$
33,794

$
37,641

Operating income
4,816

1,571

2,581

1,862

3,200

Earnings/(loss) from continuing operations
3,333

3,266

2,309

(159
)
1,562

(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests

(451
)
(407
)
(240
)
410

(203
)
Earnings attributable to controlling interests
2,882

2,859

2,069

251

1,405

Earnings/(loss) attributable to common shareholders
2,515

2,529

1,776

(37
)
1,154

Common Stock Data
 
 
 
 
 
Earnings/(loss) per common share
 
 
 
 
 
Basic
1.46

1.66

1.95

(0.04
)
1.39

Diluted
1.46

1.65

1.93

(0.04
)
1.37

Dividends paid per common share
2.68

2.41

2.12

1.86

1.40

 
December 31,
 
20181

20171

20161

2015

2014

(millions of Canadian dollars)
 



 
Consolidated Statements of Financial Position
 
 
 
 
 
Total assets2
$
166,905

$
162,093

$
85,209

$
84,154

$
72,280

Long-term debt including capital leases, less current portion
60,327

60,865

36,494

39,391

33,423

1
Our Consolidated Statements of Earnings and Consolidated Statements of Financial Position data reflect the following acquisitions, dispositions and impairment:
2018 - Canadian Natural Gas Gathering and Processing business impairment and gain on disposition of provincially regulated assets, Midcoast Operating, L.P. impairment and loss on disposition, Line 10 impairment, and other losses on disposition.
2017 - Spectra Merger Transaction, acquisition of public interest in Midcoast Energy Partners, L.P. and other impairment
2016 - Sandpiper Project impairment, gain on disposition of South Prairie Region assets, Tupper Plants acquisition and other.
2
We combined Cash and cash equivalents and other amounts previously presented as Bank indebtedness where the corresponding bank accounts are subject to pooling arrangements.




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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", 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.
SIMPLIFICATION OF CORPORATE STRUCTURE
On May 17, 2018, we announced four separate non-binding all-share proposals to the respective boards of directors of our sponsored vehicles, Spectra Energy Partners, LP (SEP), Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEM) and Enbridge Income Fund Holdings Inc. (ENF), (collectively, the Sponsored Vehicles), to acquire, in separate combination transactions, all of the outstanding equity securities of those sponsored vehicles not beneficially owned by us.
On August 24, 2018, we announced that we entered into a definitive agreement with SEP under which we would acquire all of the outstanding public common units of SEP on the basis of 1.111 of our common shares for each common unit of SEP. Closing of the transaction occurred on December 17, 2018, resulting in us acquiring all of the outstanding public common units of SEP and SEP becoming a wholly-owned subsidiary of Enbridge Inc. (Enbridge). The transaction is valued at $3.9 billion based on the closing price of our common shares on the New York Stock Exchange (NYSE) on December 14, 2018.
On September 18, 2018, we announced that we entered into definitive agreements with each of EEP and EEM under which we would acquire all of the outstanding public class A common units of EEP and all of the outstanding public listed shares of EEM. EEP public unitholders will receive 0.335 of our common shares for each class A common unit of EEP, and EEM public shareholders will receive 0.335 of our common shares for each listed share of EEM. Closing of the transactions occurred on December 20, 2018. The closing of the EEP transaction resulted in us acquiring all of the outstanding public class A common units of EEP and EEP becoming a wholly-owned subsidiary of Enbridge. The closing of the EEM transaction resulted in us acquiring all of the outstanding public listed shares of EEM and EEM becoming a wholly-owned subsidiary of Enbridge. The EEP and EEM transactions are valued at $3.0 billion and $1.3 billion, respectively, based on the closing price of our common shares on the NYSE on December 19, 2018.

On September 18, 2018, we announced that we entered into a definitive agreement with ENF under which we would acquire all of the issued and outstanding public common shares of ENF on the basis of 0.735 of our common shares and cash of $0.45 for each common share of ENF. Closing of the transaction occurred on November 8, 2018, resulting in us acquiring all of the issued and outstanding public common shares of ENF and ENF becoming a wholly-owned subsidiary of Enbridge. The transaction, excluding the cash portion, is valued at $4.5 billion based on the closing price of our common shares on the Toronto Stock Exchange on November 7, 2018.

ASSET MONETIZATION

Renewable Assets
On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets, a 49% interest in two United States renewable assets and 49% of our interest in the Hohe See Offshore wind power project and its subsequent expansion, both concurrently under construction in Germany, (collectively, the Renewable Assets) to the Canada Pension Plan Investment Board (CPPIB). Total cash proceeds from the transaction were $1.75 billion. In addition, CPPIB will fund their pro-rata share of the

52


remaining capital expenditures on the Hohe See Offshore wind project. We maintain a 51% interest in the Renewable Assets and will continue to manage, operate and provide administrative services for these assets.

Midcoast Operating, L.P.
On August 1, 2018, we closed the sale of Midcoast Operating, L.P. and its subsidiaries (collectively, MOLP) to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for total cash proceeds of $1.4 billion (US$1.1 billion).

Canadian Natural Gas Gathering and Processing Businesses
On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses for a cash purchase price of approximately $4.3 billion to Brookfield Infrastructure Partners L.P. and its institutional partners. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations. On October 1, 2018, we closed the sale of the provincially regulated facilities for proceeds of approximately $2.5 billion. The sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion.

Enbridge Gas New Brunswick Business
On December 4, 2018, we announced that we entered into a definitive agreement for the sale of Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (together, EGNB) to Liberty Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp., for a cash purchase price of $331 million. Closing of the transaction remains subject to the receipt of regulatory approvals and other customary closing conditions expected to occur in 2019.

Refer to Liquidity and Capital Resources - Sources and Uses of Cash for details on the use of proceeds from our asset monetization activity discussed above.

ONTARIO ENERGY BOARD DECISION ON AMALGAMATION
On August 30, 2018, we received a decision from the Ontario Energy Board (OEB) approving the application to amalgamate Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas). On October 15, 2018, we announced that we will proceed with the amalgamation of EGD and Union Gas, with an expected effective date of January 1, 2019. On January 1, 2019, the amalgamation was completed and the amalgamated company continued as Enbridge Gas Inc. (EGI).

MINNESOTA PUBLIC UTILITIES COMMISSION APPROVAL OF U.S. LINE 3 REPLACEMENT PROGRAM
On June 28, 2018, the Minnesota Public Utilities Commission (MNPUC) approved the issuance of a Certificate of Need (Certificate) and pipeline route (Route Permit) for construction of the United States Line 3 Replacement Program (U.S. L3R Program) in Minnesota. The Route Permit adopted our preferred route, with minor modifications and subject to certain conditions. For further details refer to Growth Projects - Regulatory Matters - United States Line 3 Replacement Program.

REVISED FERC POLICY ON TREATMENT OF INCOME TAXES

On March 15, 2018, the Federal Energy Regulatory Commission (FERC) revised a long standing policy announcing that it would no longer permit entities organized as Master Limited Partnerships (MLPs) to recover an income tax allowance for interstate pipeline assets with cost-of-service rates. The announcement of the Revised Policy Statement was accompanied by: (i) a Notice of Proposed Rulemaking proposing interstate natural gas pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the revised Policy Statement on each pipeline; and (ii)

53


a Notice of Inquiry seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation.
We hold our United States liquids and natural gas pipelines through a number of different ownership structures. We responded to the FERC announcement regarding tax allowance, both directly and through industry associations, objecting to the change in FERC policy and requesting a re-hearing. On April 27, 2018, the FERC issued a tolling order for the purpose of affording it additional time for consideration of matters raised on rehearing. These FERC announcements have adversely affected MLPs generally.
On July 18, 2018, the FERC issued an Order that: (1) dismissed all requests for rehearing of its March 15, 2018 revised policy statement and explained that its revised policy statement does not establish a binding rule, but is instead an expression of general policy that the Commission intends to follow in the future; and (2) provides guidance that if an MLP or other tax pass-through pipeline eliminates its income tax allowance from its cost of service pursuant to FERC’s Revised Policy Statement, then Accumulated Deferred Income Taxes (ADIT) will similarly be removed from its cost of service and MLP pipelines may also eliminate previously-accumulated sums in ADIT. As a statement of general policy, the FERC will consider alternative application of its tax allowance and ADIT policy on a case-by-case basis.
There are many uncertainties with regards to the implementation of the recent FERC actions, including the potential for different outcomes as the result of a rate case or customer challenges. We expect that the elimination of our MLP structures, resulting from the buy-in of our Sponsored Vehicles, will allow for all applicable pipelines, 100% owned by us, to qualify for an income tax allowance.

UNITED STATES TAX REFORM

On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (TCJA or United States Tax Reform). As disclosed in our Annual Report on Form 10-K, filed with the Securities and Exchange Commission on February 16, 2018, for the year ending December 31, 2017, we recognized reasonable estimates for 1) effects to our deferred tax balances for the impact of the tax rate decrease; and 2) the one time impact for the repatriation tax. While our accounting for tax reform pursuant to SAB 118 is complete, the ultimate impact from the TCJA, whether adverse or favorable, is still uncertain. While the United States Treasury has issued substantial guidance in 2018 in the form of proposed regulations, uncertainty will still exist until the regulations are finalized.

During the first quarter of 2018 we refined our calculation of the regulatory liability associated with the TCJA which resulted in a $30 million reduction to the overall regulatory liability. An additional reduction to the regulatory liability in the amount of $223 million was recorded in the fourth quarter of 2018 in connection with rate cases filed that eliminated a portion of the regulatory liability formerly included in our US Gas Transmission businesses rate base.

We recorded $43 million in tax expense for the year ended December 31, 2018, in connection with the Base Erosion and Anti-abuse Tax (BEAT), and we recorded no provision for the Global Intangible Low Taxed Income Tax (GILTI).


54


RESULTS OF OPERATIONS
 
Year ended
December 31,
 
2018

2017

2016

(millions of Canadian dollars, except per share amounts)
 

 

 

Segment earnings/(loss) before interest, income taxes and depreciation and amortization
 

 

 

Liquids Pipelines
5,331

6,395

4,926

Gas Transmission and Midstream
2,334

(1,269
)
464

Gas Distribution
1,711

1,390

831

Green Power and Transmission
369

372

344

Energy Services
482

(263
)
(183
)
Eliminations and Other
(708
)
(337
)
(101
)
 
 
 
 
Depreciation and amortization
(3,246
)
(3,163
)
(2,240
)
Interest expense
(2,703
)
(2,556
)
(1,590
)
Income tax recovery/(expense)
(237
)
2,697

(142
)
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests
(451
)
(407
)
(240
)
Preference share dividends
(367
)
(330
)
(293
)
Earnings attributable to common shareholders
2,515

2,529

1,776

Earnings per common share
1.46

1.66

1.95

Diluted earnings per common share
1.46

1.65

1.93



55


EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Year ended December 31, 2018 compared with year ended December 31, 2017

Earnings Attributable to Common Shareholders for the year ended December 31, 2018 were positively impacted by contributions in the first two months of 2018 of approximately $364 million from assets whose performance was not reflected in Earnings Attributable to Common Shareholders for the first two months of 2017 due to the timing of the completion of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction).

After taking into consideration the contribution of additional earnings from the Merger Transaction, Earnings Attributable to Common Shareholders was negatively impacted by $1,600 million due to certain unusual, infrequent or other factors, primarily explained by the following:
a goodwill impairment charge of $1,019 million in 2018 resulting from the classification of our Canadian natural gas gathering and processing businesses as held for sale, refer to Item 8. Financial Statements and Supplementary Data - Note 8. Acquisitions and Dispositions - Dispositions;
a loss in 2018 of $913 million ($701 million after-tax attributable to us) on MOLP resulting from a revision to the fair value of the assets held for sale based on the sale price; refer to Item 8. Financial Statements and Supplementary Data - Note 8. Acquisitions and Dispositions - Dispositions;
a non-cash, unrealized derivative fair value loss of $894 million ($568 million after-tax attributable to us) in 2018, compared with a gain of $1,109 million ($624 million after-tax attributable to us) in the corresponding 2017 period, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity prices risks;
a loss of $154 million ($95 million after-tax attributable to us) in 2018 related to the Line 10 crude oil pipeline (Line 10), which is a component of our mainline system, resulting from its classification as an asset held for sale and the subsequent measurement at the lower of carrying value or fair value less costs to sell;
asset monetization transaction costs of $88 million ($80 million after-tax attributable to us) recorded in 2018 attributable to divestiture activity in the year, refer to Asset Monetization;
the absence in 2018 of a non-cash, $1,936 income tax benefit ($2,045 million federal tax recovery net of a $109 million state deferred tax expense) due to the enactment of the TCJA by the United States in December 2017, refer to Item 8. Financial Statements and Supplementary Data - Note 25. Income Taxes; partially offset by
the absence in 2018 of a loss of $4,391 million ($2,753 after-tax attributable to us) and related goodwill impairment of $102 million recorded in 2017 resulting from the classification of MOLP assets as held for sale and the subsequent measurement at the lower of their carrying value or fair value less costs to sell, refer to Item 8. Financial Statements and Supplementary Data - Note 8. Acquisitions and Dispositions - Dispositions;
a deferred income tax recovery of $267 million ($196 million after-tax attributable to us) in 2018 related to a change in the assertion for the investment in Canadian renewable energy generation assets due to the pending sale which resulted in a revaluation of the related deferred tax liability to the capital gains tax rate and recognition of previously unrecognized tax basis;
employee severance, transition and transformation costs of $203 million ($181 million after-tax attributable to us) in 2018, compared with $354 million ($273 million after-tax attributable to us) in the corresponding 2017 period;
the absence in 2018 of transaction costs of $180 million ($131 million after-tax attributable to us) recorded in 2017 related to the Merger Transaction;
a recovery of $223 million after-tax attributable to us in 2018 related to rate cases filed that eliminated a portion of the regulated liability formerly included in our US Gas Transmission businesses rate base, refer to United States Tax Reform; and

56


a gain of $63 million after-tax attributable to us in 2018 resulting from the impact of United States Tax Reform on our United States Green Power and Transmission assets.

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

After taking into consideration the factors above, the remaining $1,222 million increase in Earnings Attributable to Common Shareholders is primarily explained by the following significant business factors:
stronger contributions from our Liquids Pipelines segment due to a higher foreign exchange hedge rate used to lock-in United States dollar denominated Canadian Mainline revenues, a higher IJT Benchmark Toll and higher throughput driven by the full year impact of capacity optimization initiatives implemented in 2017;
contributions from new Liquids Pipelines assets placed into service in 2017;
contributions from new Gas Transmission and Midstream assets placed into service in 2017 and 2018;
increased earnings from some of our Gas Transmission and Midstream equity investments due to favorable margins, favorable commodity prices and increased volume commitments;
increased earnings from our Gas Distribution segment due to colder weather, expansion projects and higher distribution charges resulting from growth in rate base; and
increased earnings from our Energy Services segment due to the widening of certain location differentials, which increased opportunities to generate profitable margins; partially offset by
higher interest expense primarily due to long-term debt issuances in 2017 and the first half of 2018 to finance capital expansions; and
higher income tax expense driven by higher earnings from the business factors described above.

Lower earnings per common share for 2018 is primarily due to the increase in the number of common shares outstanding following the issuance of approximately 297 million common shares in the fourth quarter of 2018 resulting from the buy-in of our Sponsored Vehicles, refer to Simplification of Corporate Structure, the issuance of approximately 33 million common shares in December 2017 in a private placement offering, and the issuance of approximately 691 million common shares in February 2017 as part of the consideration for the Merger Transaction. This dilutive effect was partially offset by the increase in Earnings Attributable to Common Shareholders resulting from the factors discussed above.

Year ended December 31, 2017 compared with year ended December 31, 2016

Earnings Attributable to Common Shareholders for the year ended December 31, 2017 were positively impacted by contributions in the last ten months of 2017 of approximately $2,574 million from assets whose performance was not reflected in Earnings Attributable to Common Shareholders for 2016 due to the timing of the completion of the Merger Transaction.

After taking into consideration the contribution of additional earnings from the Merger Transaction, Earnings Attributable to Common Shareholders decreased by $151 million due to certain unusual, infrequent or other factors, primarily explained by the following:
a loss of $4,391 million ($2,753 million after-tax attributable to us) and related goodwill impairment of $102 million resulting from the classification of certain assets as held for sale and the subsequent measurement at the lower of their carrying value or fair value less costs to sell, refer to Item 8. Financial Statements and Supplementary Data - Note 8. Acquisitions and Dispositions - Dispositions;
employee severance, transition and transformation costs of $354 million ($273 million after-tax attributable to us) in 2017, compared with $82 million in the corresponding 2016 period;

57


transaction costs of $180 million ($131 million after-tax attributable to us) in 2017, compared with $86 million in the corresponding 2016 period, related to the Merger Transaction; and
the absence in 2017 of a gain of $850 million ($520 million after-tax attributable to us) recorded in 2016 related to the disposition of the South Prairie Region assets; partially offset by
a non-cash, $1,936 million income tax benefit ($2,045 million federal tax recovery net of a $109 million state deferred tax expense) due to the enactment of the TCJA by the United States in December 2017, refer to Item 8. Financial Statements and Supplementary Data - Note 25. Income Taxes;
a non-cash, unrealized derivative fair value gain of $1,109 million in 2017 ($624 million after-tax attributable to us), compared with a gain of $543 million ($459 million after-tax attributable to us) in the corresponding 2016 period reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity prices risks; and
the absence in 2017 of cumulative asset impairment charges of $1,561 million ($456 million after-tax attributable to us) recorded in 2016 related to EEP's Sandpiper Project, the Northern Gateway Project and Eddystone Rail.

After taking into consideration the factors above, the remaining $1,670 million decrease in Earnings Attributable to Common Shareholders is primarily explained by the following significant business factors:
increased depreciation and amortization expense primarily resulting from a significant number of new assets placed into service in 2017;
increased interest expense primarily resulting from the settlement of certain pre-issuance hedges;
increased earnings attributable to noncontrolling interests and redeemable noncontrolling interests in 2017, compared with the corresponding 2016 period. The increase was driven by higher earnings attributable to noncontrolling interests in EEP during 2017 as a result of the EEP strategic restructuring actions; and
the absence of earnings from certain assets that were divested since the third quarter of 2016; partially offset by
strong contributions from our Liquids Pipelines segment due to higher throughput primarily attributable to capacity optimization initiatives implemented in 2017 which significantly reduced heavy crude oil apportionment allowing incremental heavy crude oil barrels to be shipped;
contributions from new Liquids Pipelines assets placed into service in 2017; and
increased earnings from our Gas Transmission and Midstream segment in 2017 due to favorable seasonal firm revenue and a full year of contributions from assets acquired in 2016.

Lower earnings per common share for 2017 is primarily due to the increase in common shares from the issuance of approximately 33 million common shares in December 2017 in a private placement offering, the issuance of approximately 691 million common shares in February 2017 as part of the consideration for the Merger Transaction, the issuance of approximately 75 million common shares in 2016 through the public offering of 56 million common shares in the first quarter of 2016, and ongoing quarterly issuances under our Dividend Reinvestment Program. Additional earnings from the assets acquired in the Merger Transaction were offset by certain unusual, infrequent or other factors, as discussed above.

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

Transportation and other services revenues of $14,358 million, $13,877 million and $9,258 million for the years ended December 31, 2018, 2017 and 2016, respectively, were earned from our crude oil and natural gas pipeline transportation businesses and also include power production revenues from our portfolio of renewable and power generation assets. For our transportation assets operating under market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in

58


accordance with tolls established by the regulator, and in most cost-of-service based arrangements are reflective of our cost to provide the service plus a regulator-approved rate of return. Higher transportation and other services revenues reflected increased throughput on our core liquids pipeline assets combined with the incremental revenues associated with assets placed into service over the past two years.

Gas distribution sales revenues of $4,360 million, $4,215 million and $2,486 million for the years ended December 31, 2018, 2017 and 2016, respectively, were recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are primarily driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through to customers through rates and does not ultimately impact earnings due to its flow-through nature.

Commodity sales of $27,660 million, $26,286 million and $22,816 million for the years ended December 31, 2018, 2017 and 2016, respectively, were generated primarily through our Energy Services operations. Energy Services includes the contemporaneous purchase and sale of crude oil, natural gas, power and Natural Gas Liquids (NGLs) to generate a margin, which is typically a small fraction of gross revenue. While sales revenue generated from these operations are impacted by commodity prices, net margins and earnings are relatively insensitive to commodity prices and reflect activity levels which are driven by differences in commodity prices between locations, grades and points in time, rather than on absolute prices. Any residual commodity margin risk is closely monitored and managed. Revenues from these operations depend on activity levels, which vary from year-to-year depending on market conditions and commodity prices.

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

DIVIDENDS
We have paid common share dividends in every year since we became a publicly traded company in 1953. In December 2018, we announced a 10% increase in our quarterly dividend to $0.738 per common share, or $2.952 annualized, effective with the dividend payable on March 1, 2019.

BUSINESS SEGMENTS

LIQUIDS PIPELINES
 
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
 
2018

2017

2016

(millions of Canadian dollars)
 

 

 

Earnings before interest, income taxes and depreciation and amortization
5,331

6,395

4,926


Year ended December 31, 2018 compared with year ended December 31, 2017

Earnings before interest, income taxes and depreciation and amortization (EBITDA) for the year ended December 31, 2018 was positively impacted by contributions in the first two months of 2018 of approximately $53 million from assets whose performance was not reflected in EBITDA for the first two months of 2017 due to the timing of the completion of the Merger Transaction.


59


After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA was negatively impacted by $2,197 million due to certain unusual, infrequent or other factors, primarily explained by the following:
a non-cash, unrealized loss of $1,077 million in 2018 compared with a gain of $875 million in 2017 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 loss of $154 million in 2018 related to Line 10, which is a component of our mainline system, resulting from its classification as an asset held for sale and the subsequent measurement at the lower of carrying value or fair value less costs to sell;
a gain of $27 million in 2018 compared with a $72 million gain in 2017 on the sale of pipe offset by project wind-down costs related to EEP's Sandpiper Project (Sandpiper);
a loss of $27 million in 2018 related to the Wood Buffalo extension pipeline resulting from a revision to the fair value of excess material based on the estimated sale price; and
the absence in 2018 of a $27 million gain recorded in 2017 on the sale of the Olympic refined products pipeline.

After taking into consideration the factors above, the remaining $1,080 million increase is primarily explained by the following significant business factors:
a higher foreign exchange hedge rate used to lock-in United States dollar denominated Canadian Mainline revenues of $1.26 in 2018 compared with $1.06 in 2017;
a higher average IJT Benchmark Toll of $4.11 in 2018 compared with $4.06 in 2017;
higher Canadian Mainline ex-Gretna throughput of 2,631 kbpd in 2018 compared with 2,530 kbpd in 2017 driven by the full year impact of capacity optimization initiatives implemented in 2017 and greater supply;
contributions from assets placed into service during 2017, including the Wood Buffalo Extension Pipeline and the Norlite Pipeline System and the acquisition of a minority interest in the Bakken Pipeline System;
higher Bakken Pipeline System and Waupisoo Pipeline throughput period-over-period; and
increased transportation revenues resulting from higher spot volumes on Flanagan South Pipeline driven by strong demand in the United States Gulf Coast.

Year ended December 31, 2017 compared with year ended December 31, 2016

EBITDA for the year ended December 31, 2017 was positively impacted by contributions in the last ten months of 2017 of approximately $285 million from assets whose performance was not reflected in EBITDA for 2016 due to the timing of the completion of the Merger Transaction.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA increased by $1,312 million due to certain unusual, infrequent or other factors, primarily explained by the following:
a non-cash, unrealized gain of $875 million in 2017 compared with a gain of $474 million in 2016 reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks;
the absence in 2017 of a $1,004 million impairment charge recorded in 2016, including related project costs, on EEP's Sandpiper resulting from the withdrawal of the regulatory applications in September 2016 that were pending with the MNPUC;
the absence in 2017 of a $373 million impairment charge recorded in 2016 related to the Northern Gateway Project due to our conclusion that the project could not proceed as envisioned as a result of the Federal Government's decision to dismiss the application for Certificate of Public Convenience and Necessity;
the absence in 2017 of a $184 million impairment charge recorded in 2016 related to our 75% joint venture interest in Eddystone Rail attributable to market conditions which impacted volumes at the rail facility; and

60


a gain of $72 million on sale of pipe partially offset by project wind-down costs related to EEP’s Sandpiper; partially offset by
the absence in 2017 of a $850 million gain recorded in 2016 related to the sale of non-core South Prairie Region assets.

After taking into consideration the factors above, the remaining $128 million decrease is primarily explained by the following significant business factors:
lower contributions from Mid-Continent assets primarily due to lower contracted storage revenues and the sale of the Ozark Pipeline system in the first quarter of 2017;
lower contributions resulting from the sale of the South Prairie Region assets in December 2016;
higher Lakehead Pipeline System (Lakehead System) operating costs including costs to implement EEP’s signed settlement agreement regarding the Lines 6A and 6B crude oil releases (the Consent Decree) approved by the United States Department of Justice (DOJ) in May 2017; and
the unfavorable effect of translating United States dollar EBITDA at a lower Average Exchange Rate of $1.30 in 2017 compared with $1.32 in 2016, inclusive of the impact of settlements under our foreign exchange hedging program; partially offset by
contributions from new assets placed into service including the Regional Oil Sands Optimization Project and the Norlite Pipeline System and the acquisition of a minority interest in the Bakken Pipeline System that went into service in June 2017;
higher Canadian Mainline ex-Gretna throughput of 2,530 kbpd in 2017 compared with 2,405 kbpd in 2016 driven by capacity optimization initiatives implemented in 2017; and
higher Lakehead System throughput of 2,673 kbpd in 2017 compared with 2,574 in 2016 driven by capacity optimization initiatives implemented in 2017.

GAS TRANSMISSION AND MIDSTREAM
 
EARNINGS/(LOSS) BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
 
2018

2017

2016

(millions of Canadian dollars)
 

 

 

Earnings/(loss) before interest, income taxes and depreciation and amortization
2,334

(1,269
)
464


Year ended December 31, 2018 compared with year ended December 31, 2017

EBITDA for the year ended December 31, 2018 was positively impacted by contributions in the first two months of 2018 of approximately $570 million from assets whose performance was not reflected in EBITDA for the first two months of 2017 due to the timing of the completion of the Merger Transaction.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA increased by $2,885 million due to certain unusual, infrequent or other market factors primarily explained by the following:
a net positive impact of $3,539 million related to the sale of MOLP due to the following:
the absence in 2018 of a loss of $4,391 million and related goodwill impairment of $102 million recorded in 2017 resulting from the classification of assets as held for sale and the subsequent measurement at the lower of their carrying value or fair value less costs to sell; partially offset by
a loss of $913 million in 2018 resulting from the further revision to the fair value of the assets held for sale based on the sale price; and
a loss of $41 million in 2018 resulting from the sale of the assets.

61


a recovery of $223 million in 2018 related to rate cases filed that eliminated a portion of the regulated liability formerly included in our US Gas Transmission businesses rate base, refer to United States Tax Reform;
a non-cash, equity earnings adjustment of $12 million in 2018 compared with $28 million in 2017 related to asset write-down losses and changes in the mark-to-market fair value of derivative financial instruments at our equity investee, DCP Midstream, LLC (DCP Midstream);
a gain of $34 million in 2018 resulting from the sale of the provincially regulated portion of our Canadian natural gas gathering and processing businesses;
a non-cash, unrealized gain of $24 million in 2018 compared with a loss of $1 million in 2017 reflecting net fair value gains and losses arising from the change in the mark-to-market fair value of derivative financial instruments used to manage foreign exchange and commodity price risk; and
the absence in 2018 of pipeline inspection and repair costs of $26 million recorded in 2017 primarily due to the 2017 Texas Eastern Transmission, L.P. (Texas Eastern) pipeline incident; partially offset by
a goodwill impairment charge of $1,019 million in 2018 resulting from the classification of our Canadian natural gas gathering and processing businesses as held for sale; and
asset monetization transaction costs of $20 million recorded in 2018 resulting from the termination of MOLP commodity hedges.

After taking into consideration the factors above, the remaining $148 million increase is primarily explained by the following significant business factors:
contributions from assets placed into service in 2018, including NEXUS, Valley Crossing, High Pine and Wyndwood pipelines;
contributions from assets placed into service in the second half of 2017, including Sabal Trail Transmission, LLC (Sabal Trail), Access South, Adair Southwest and Lebanon Extension pipelines;
increased fractionation margins at our Aux Sable joint venture driven by higher NGL prices and increased demand;
favorable seasonal firm and interruptible revenues from our Alliance joint venture that resulted from wider basis differentials; and
increased earnings from our DCP Midstream LP joint venture driven by favorable commodity prices and increased volumes.

Year ended December 31, 2017 compared with year ended December 31, 2016

EBITDA for the year ended December 31, 2017 was positively impacted by contributions in the last ten months of 2017 of approximately $2,557 million from assets whose performance was not reflected in EBITDA for 2016 due to the timing of the completion of the Merger Transaction. When compared to pre-merger results from the prior year, operating results from the new assets include higher earnings primarily from business expansion projects on Algonquin Gas Transmission, Sabal Trail and Texas Eastern.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $4,287 million due to certain unusual, infrequent or other market factors primarily explained by the following:
a loss of $4,391 million and related goodwill impairment of $102 million resulting from the classification of MOLP assets as held for sale and the subsequent measurement at the lower of their carrying value or fair value less costs to sell; partially offset by
a non-cash, unrealized loss of $1 million in 2017 compared with a loss of $139 million in 2016 reflecting net fair value gains and losses arising from the change in the mark-to-market of derivative financial instruments used to manage foreign exchange and commodity price risk.

After taking into consideration the factors above, the remaining $3 million decrease is primarily explained by the following significant business factors:

62


lower commodity prices which impacted production volume in areas served by some of our United States Midstream assets; partially offset by
favorable seasonal firm revenues from our Alliance joint venture that resulted from wider basis differentials;
contributions from the Tupper Main and Tupper West gas plants that were acquired in April 2016;
increased fractionation margins driven by higher NGL prices and increased demand from our Aux Sable joint venture; and
higher volumes from our Offshore assets and higher earnings from certain joint venture pipelines.

GAS DISTRIBUTION
 
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
 
2018

2017

2016

(millions of Canadian dollars)
 

 

 

Earnings before interest, income taxes and depreciation and amortization
1,711

1,390

831

 
Year ended December 31, 2018 compared with year ended December 31, 2017

EBITDA for the year ended December 31, 2018 was positively impacted by contributions in the first two months of 2018 of approximately $180 million from Union Gas whose performance was not reflected in EBITDA for the first two months of 2017 due to the timing of the completion of the Merger Transaction.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA was negatively impacted by $26 million due to certain unusual, infrequent and other business factors, primarily explained by the following:
a non-cash, unrealized gain of $6 million in 2018 compared with a gain of $16 million in 2017 arising from the change in the mark-to-market value of our equity investee's, Noverco Inc.'s (Noverco) derivative financial instruments;
a negative equity earnings adjustment of $9 million of our equity investee, Noverco in 2018 arising from United States Tax Reform; and
employee severance, transition and transformation costs of $12 million in 2018 compared with $5 million in 2017.

After taking into consideration the factors above, the remaining $167 million increase is primarily explained by the following significant business factors:
increased earnings of $47 million period-over-period resulting from colder weather experienced in our franchise service areas when compared to the corresponding period in 2017; and
higher earnings from expansion projects, and higher distribution charges primarily resulting from increases in rate base and customer base.

Year ended December 31, 2017 compared with year ended December 31, 2016

EBITDA for the year ended December 31, 2017 was positively impacted by contributions in the last ten months of 2017 of approximately $545 million from Union Gas whose performance was not reflected in EBITDA for 2016 due to the timing of the completion of the Merger Transaction. When compared to pre-merger results from prior years, Union Gas' operating results benefited mainly from higher transportation revenue from the Dawn-Parkway expansion projects, increased storage optimization and increases in delivery rates, partially offset by higher operating costs.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA increased by $14 million due to certain unusual, infrequent and other business factors, primarily explained by the following:

63


a non-cash, unrealized gain of $16 million in 2017 compared with a loss of $6 million in 2016 arising from the change in the mark-to-market value of Noverco's derivative financial instruments; and
warmer than normal weather experienced during 2017 which negatively impacted EBITDA by $15 million compared with $18 million in 2016; partially offset by
the absence in 2017 of other regulatory adjustments at Noverco of $17 million recorded in 2016.

GREEN POWER AND TRANSMISSION
 
EARNINGS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
 
2018

2017

2016

(millions of Canadian dollars)
 

 

 

Earnings before interest, income taxes and depreciation and amortization
369

372

344


Year ended December 31, 2018 compared with year ended December 31, 2017

EBITDA was negatively impacted by $59 million due to certain unusual, infrequent and other factors, primarily explained by the following:
a loss of $20 million in 2018 resulting from the sale of 49% of our interest in the Hohe See Offshore wind facilities and its subsequent expansion;
an asset impairment charge of $22 million in 2018 from our equity investment in NRGreen Power Limited Partnership related to the Chickadee Creek waste heat recovery facility in Alberta; and
a loss of $25 million in 2018 representing our share of losses incurred by our equity investee, Rampion Offshore Wind Limited, primarily due to the repair and restoration of damaged cables; partially offset by
the absence in 2018 of a $9 million loss recorded in 2017 resulting from the sale of an investment.

After taking into consideration the factors above, the remaining $56 million increase is primarily explained by the following significant business factors:
stronger wind resources and lower operating costs at Canadian and United States wind facilities;
contributions from the Rampion Offshore Wind Project, which generated first power in November 2017 and reached full operating capacity in the second quarter of 2018; and
a net gain of $11 million from an arbitration settlement related to our Canadian wind facilities.

Year ended December 31, 2017 compared with year ended December 31, 2016

EBITDA increased by $4 million due to certain unusual, infrequent and other factors, primarily explained by the following:
the absence in 2017 of a $13 million loss recorded in 2016 resulting from an investment impairment; partially offset by
a $9 million loss that resulted from the sale of an investment recorded in 2017.

After taking into consideration the factors above, the remaining $24 million increase is primarily explained by the following significant business factors:
stronger wind resources at Canadian and United States wind facilities; and
contributions from new United States wind projects placed into service in 2016 and 2017.

ENERGY SERVICES
 
EARNINGS/(LOSS) BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION

64


 
2018

2017

2016

(millions of Canadian dollars)
 

 

 

Earnings/(loss) before interest, income taxes and depreciation and amortization
482

(263
)
(183
)

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, 2018 compared with year ended December 31, 2017

EBITDA increased by $526 million due to certain unusual, infrequent and other factors, primarily explained by the following:
a non-cash, unrealized gain of $408 million in 2018 compared with a loss of $200 million in 2017 reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and exposure to movements in commodity prices; partially offset by
a non-cash loss of $93 million in 2018 resulting from the write-down of inventory to the lower of cost or market.

After taking into consideration the factor above, the remaining $219 million increase is primarily due to increased earnings from Energy Services' Canadian and United States crude operations due to the widening of certain location differentials in 2018, which increased opportunities to generate profitable margins.

Year ended December 31, 2017 compared with year ended December 31, 2016

EBITDA increased by $2 million primarily due to a non-cash, unrealized loss of $200 million in 2017 compared with a loss of $205 million in 2016 reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and exposure to movements in commodity prices.

After taking into consideration the factor above, the remaining $82 million decrease is primarily due to weaker performance from Energy Services’ Canadian and United States operations due to the compression of certain crude oil and NGL location and quality differentials in 2017 which limited opportunities to generate profitable margins.



65


ELIMINATIONS AND OTHER
 
LOSS BEFORE INTEREST, INCOME TAXES AND DEPRECIATION AND AMORTIZATION
 
2018

2017

2016

(millions of Canadian dollars)
 

 

 

Loss before interest, income taxes and depreciation and amortization
(708
)
(337
)
(101
)

Eliminations and Other includes operating and administrative costs and the impact of foreign exchange hedge settlements which are not allocated to business segments. Eliminations and Other also includes new business development activities, general corporate investments and reflect a portion of the synergies on the integration of corporate functions in relation to the Merger Transaction.

Year ended December 31, 2018 compared with year ended December 31, 2017

EBITDA decreased by $430 million due to certain unusual, infrequent and other factors, primarily explained by the following:
a non-cash, unrealized loss of $256 million in 2018 compared with a gain of $417 million in 2017 reflecting net fair value gains and losses arising from the change in the mark-to-market fair value of derivative financial instruments used to manage foreign exchange risk; and
asset monetization transaction costs of $68 million recorded in 2018; partially offset by
employee severance, transition and transformation costs of $152 million in 2018 compared with $292 million in 2017; and
the absence in 2018 of transaction costs compared with $174 million of costs recorded in 2017 related to the Merger Transaction.

After taking into consideration the factors above, the remaining $59 million increase is primarily explained by the following significant business factors:
synergies achieved on the integration of corporate functions; partially offset by
a realized loss of $219 million in 2018 compared with a loss of $184 million in 2017 related to settlements under our foreign exchange risk management program.

Year ended December 31, 2017 compared with year ended December 31, 2016

EBITDA decreased by $315 million due to certain unusual, infrequent and other factors, primarily explained by the following:
transaction costs of $174 million incurred in 2017 compared with $81 million in 2016 related to the Merger Transaction;
employee severance, transition and transformation costs of $292 million in 2017 compared with $92 million in 2016; and
project development costs of $23 million in 2017; partially offset by
a non-cash, unrealized intercompany foreign exchange loss of $29 million in 2017 compared with a loss of $43 million in 2016 under our foreign exchange risk management program.

After taking into consideration the factors above, the remaining $79 million increase is primarily explained by a realized loss of $173 million in 2017 compared with a loss of $281 million in 2016 related to settlements under our foreign exchange risk management program.



66


GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS
 
The following table summarizes the status of our commercially secured projects, organized by business segment:
 
 
 
Enbridge's Ownership Interest

 
Estimated
Capital Cost1
 
Expenditures
to Date2
 
Status
 
Expected
In-Service
Date
(Canadian dollars, unless stated otherwise)
 
 
 
 
 
 
 
 
LIQUIDS PIPELINES
 
 
 
 
 
 
 
 
 
1

 
Canadian Line 3 Replacement Program
100
%
 
$5.3 billion
 
$4.1 billion
 
Under
 
2H - 2019
 

 
 
 
 
 
 
 
construction
 
 
2

 
U.S. Line 3 Replacement Program
100
%
 
US$2.9 billion
 
US$1.0 billion
 
Pre-
 
2H - 2019
 

 
 
 
 
 
 
 
construction3
 
 
3

 
Gray Oak Pipeline Project
22.8
%
 
US$0.6 billion
 
No significant
 
Under
 
2H - 2019
 
 
 
 
 
 
 
expenditures to date
 
construction
 
 
4

 
Other - United States4
100
%
 
US$0.4 billion
 
US$0.4 billion
 
Substantially
 
2H - 2019
 
 
 
 
 
 
 
 
 
complete
 
 
5

 
Other - Canada5
100
%
 
$0.4 billion
 
$0.1 billion
 
Various
 
1H - 2019
 
 
 
 
 
 
 
 
 
stages
 
 
GAS TRANSMISSION & MIDSTREAM
 
 
 
 
 
 
 
 
6

 
Atlantic Bridge
100
%
 
US$0.6 billion
 
US$0.5 billion
 
Under
 
1H - 2020
 

 
 
 
 
 
 
 
 
construction
 
 
7

 
NEXUS
50
%
 
US$1.3 billion
 
US$1.1 billion
 
Complete
 
In service
 
 
 
 
 
 
 
 
 
 
 
 
8

 
Reliability and Maintainability Project
100
%
 
$0.5 billion
 
$0.5 billion
 
Complete
 
In service
 
 
 
 
 
 
 
 
 
 
 
9

 
Valley Crossing Pipeline
100
%
 
US$1.6 billion
 
US$1.6 billion
 
Complete
 
In service
 
 
 
 
 
 
 
 
 
 
 
 
10

 
Spruce Ridge Program
100
%
 
$0.5 billion
 
$0.1 billion
 
Pre-
 
2H - 2020
 

 
 
 
 
 
 
 
 
construction
 
 
11

 
T-South Expansion Program
100
%
 
$1.0 billion
 
$0.1 billion
 
Pre-
 
2H - 2021
 
 
 
 
 
 
 
 
construction
 
 
12

 
Other - United States6
100
%
 
US$2.7 billion
 
US$1.1 billion
 
Various
 
2019 - 2023
 
 
 
 
 
 
 
 
 
stages
 
 
13

 
Other - Canada7
100
%
 
$0.6 billion
 
$0.6 billion
 
Complete
 
In service
 
 
 
 
 
 
 
 
 
 
 
 
GREEN POWER & TRANSMISSION
 
 
 
 
 
 
 
 
14

 
Rampion Offshore Wind Project
24.9
%
 
$0.8 billion
 
$0.6 billion
 
Complete
 
In service
 

 
 
 
(£0.37 billion)
 
(£0.3 billion)
 
 
 
 
15

 
Hohe See Offshore Wind Project and Expansion8
25
%
 
$1.1 billion
 
$0.6 billion
 
Under
 
2H - 2019
 

 
 
 
(€0.67 billion)
 
(€0.4 billion)
 
construction
 
 
16

 
Other - Canada
25
%
 
$0.2 billion
 
No significant
 
Pre-
 
2H - 2021
 
 
 
 
 
 
 
expenditures to date
 
construction
 
 
1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.
2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2018.
3 Construction of the Wisconsin portion of the project is complete as noted below. The remaining project is in pre-construction status.
4 Includes the Lakehead System Mainline Expansion - Line 61. Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program.
5 Includes the $0.1 billion Line 45 Cheecham connectivity placed into service in the second quarter of 2018.
6 Includes the US$0.2 billion Stampede Offshore oil lateral placed into service in the first quarter of 2018, the US$0.2 million Texas Eastern Appalachian Lease project placed into service in the fourth quarter of 2018, and the US$0.4 million South Texas Expansion Project and Pomelo Connector Pipeline Project placed into service in the fourth quarter of 2018.
7 Includes the $0.4 billion High Pine and the $0.2 billion Wyndwood pipeline expansion, both placed into service in the first quarter of 2018.
8 Upon closing of the sale of our Renewable Assets, our ownership interest was reduced to approximately 25%. Refer to Asset Monetization.

67



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

LIQUIDS PIPELINES
The following commercially secured growth projects are expected to be placed into service in 2019:

Canadian Line 3 Replacement Program - replacement of the existing Line 3 crude oil pipeline between Hardisty, Alberta and Gretna, Manitoba. The Canadian L3R Program will restore the original capacity of 760,000 bpd, an increase of approximately 370,000 bpd. This will support the safety and operational reliability of the overall system, enhancing flexibility and allowing us to optimize throughput from western Canada into Superior, Wisconsin. Construction commenced in early August 2017 and is nearing completion.

United States Line 3 Replacement Program - replacement of the existing Line 3 crude oil pipeline between Neche, North Dakota and Superior, Wisconsin. The U.S. L3R Program will support the safety and operational reliability of the mainline system, enhance system flexibility, and allow us to optimize throughput on the mainline. The L3R Program is expected to achieve the original capacity of approximately 760,000 bpd. The Wisconsin portion of the U.S. L3R Program is in service. For additional updates on the project, refer to Growth Projects - Regulatory Matters.

Gray Oak Pipeline Project - a crude oil pipeline project connecting West Texas to destinations in the Corpus Christi and Sweeny/Freeport markets. The pipeline is a joint development with Phillips 66 and could have an ultimate capacity of approximately 900,000 bpd, subject to additional shipper commitments.

68


enbgrowth2019lpa02.jpg

69


GAS TRANSMISSION AND MIDSTREAM
The following commercially secured growth projects were placed into service in 2018:

NEXUS - a natural gas pipeline system connecting the Texas Eastern pipeline system in Ohio to the Union Gas Dawn Hub in Ontario, via Vector Pipeline L.P., that provides capacity of up to approximately 1.5 billion cubic feet per day (bcf/d). The project was placed into service in October 2018.

Reliability and Maintainability Project - a natural gas pipeline project designed to enhance the performance of the southern segment of the British Columbia (BC) Pipeline system to accommodate the increased base load on the system. The project involved adding new compressor units at three compressor stations along the pipeline system as well as upgrading existing pipeline crossovers and adding new crossovers at key locations. The project was placed into service in August 2018.

Valley Crossing Pipeline - a natural gas pipeline connecting the Agua Dulce hub in Texas to an offshore tie-in with the Sur de Texas-Tuxpan project. The project will help Mexico meet its growing gas fired electric generation needs by providing capacity of up to approximately 2.6 bcf/d. The project was placed into service in October 2018.

The following commercially secured growth projects are expected to be placed into service in 2020:

Atlantic Bridge - expansion of the Algonquin Gas Transmission systems to transport 133 mmcf/d of natural gas to the New England Region. The expansion primarily consists of various meter station additions, the replacement of a natural gas pipeline in Connecticut and Massachusetts, compression additions in Connecticut, and a new compressor station in Massachusetts. The meter stations were placed into service in 2017 and 2018. The Connecticut portion of the project was placed into service in the fourth quarter of 2017. The New York portion of the project achieved partial in-service in November 2018 and full in-service is expected in the first quarter of 2019, upon which we will begin earning incremental revenues. Due to ongoing permitting delays in Massachusetts, the revised expected in-service date for the Massachusetts portion is the first half of 2020.

Spruce Ridge Program - a natural gas pipeline expansion of Westcoast Energy Inc.’s BC Pipeline in northern BC, which consists of the Aitken Creek Looping project and the Spruce Ridge Expansion project. The combined projects will provide additional capacity of up to 402 mmcf/d. As a result of regulatory delays, the revised expected in-service date for the program is the second half of 2020.

The following commercially secured growth project is expected to be placed into service in 2021:

T-South Expansion Program - a natural gas pipeline expansion of Westcoast Energy Inc.’s T-South system that will provide additional capacity of approximately 190 mmcf/d into the Huntington/Sumas market at the United States/Canada border. As a result of regulatory delays, the revised expected in-service date for the program is the second half of 2021.

70


enbgrowth2019gtma01.jpg


71


GREEN POWER AND TRANSMISSION
The following commercially secured growth project was placed into service in 2018:

Rampion Offshore Wind Project - a wind project located off the Sussex coast in the United Kingdom, consisting of 116 turbines, which will generate approximately 400-MW. We hold an effective 24.9% interest, United Kingdom’s Green Investment Bank plc holds a 25% interest and E.ON SE holds the remaining 50.1% interest in the project, which was developed and is being constructed by E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE. The Rampion Offshore Wind Project is backed by revenues from the United Kingdom’s fixed-price Renewable Obligation certificates program and a 15-year power purchase agreement. The project generated first power in November 2017 and full operating capacity was reached in the second quarter of 2018.

The following commercially secured growth project is expected to be placed into service in 2019:

Hohe See Offshore Wind Project and Expansion - a wind project located in the North Sea, off the coast of Germany that will generate approximately 497-MW, with an additional 112-MW from the expansion. The Hohe See Offshore Wind Project and Expansion will be constructed under fixed-price engineering, procurement, construction and installation contracts, which have been secured with key suppliers. The Hohe See Project and Expansion is backed by a government legislated 20-year revenue support mechanism.

72


enbgrowth2019gpta02.jpg

GROWTH PROJECTS - REGULATORY MATTERS

United States Line 3 Replacement Program
The MNPUC approved the Certificate and Route Permit and denied petitions to reconsider the decisions. All related Certificate conditions have been finalized and are being addressed. In addition, agreement was reached with the Fond du Lac Band of Lake Superior Chippewa granting a new 20 year easement for

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the entire Mainline including the Line 3 Replacement Project through their Reservation. The remaining permit applications have been submitted to the various federal and state agencies, including the United States Army Corps of Engineers (Army Corps), the Minnesota Department of Natural Resources, the Minnesota Pollution Control Agency and other local government agencies in Minnesota.

We anticipate that the agencies will process all of these applications in the coming months, and with timely approvals continue to expect an in-service date for the project before the end of 2019.

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

LIQUIDS PIPELINES

Texas COLT Offshore Loading Project - the Texas COLT Offshore Loading Project will facilitate the direct loading of very large crude carriers from Freeport, Texas. The project consists of a terminal, a 42-inch offshore pipeline, platform and two single point mooring systems with connectivity to all key North American supply basins. The project is a joint development with Kinder Morgan Inc. and Oiltanking, and is expected to be in service by 2022.

GREEN POWER AND TRANSMISSION

Éolien Maritime France SAS - a 50% interest in Éolien Maritime France SAS (EMF), a French offshore wind development company, which is co-owned by EDF Energies Nouvelles, a subsidiary of Électricité de France S.A. EMF holds licenses for three large-scale offshore wind facilities off the coast of France that would generate approximately 1,428 MW. The development of these projects is subject to a final investment decision and regulatory approvals, the timing of which is not yet certain.

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

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

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market conditions are attractive. In accordance with our funding plan and the simplification of corporate structure, we completed the following issuances in 2018:
Entity
Type of Issuance
Amount
(in millions of Canadian dollars, unless stated otherwise)
 
Enbridge Inc.
Common shares1
$12,727
Enbridge Inc.
US$ Fixed-to-floating rate subordinated notes
  US$1,450
Enbridge Inc.
Fixed-to-floating rate subordinated notes
$750
Texas Eastern Transmission, LP
Senior notes
US$800
1
In connection with the Sponsored Vehicles buy-in, refer to Simplification of Corporate Structure.

Credit Facilities, Ratings and Liquidity
To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities at December 31, 2018.
 
 
2018
 
 
Total

 

 

December 31,
Maturity
Facilities

Draws1

Available

(millions of Canadian dollars)
 
 

 

 

Enbridge Inc.
2019-2023
5,751

2,008

3,743

Enbridge (U.S.) Inc.
2020
1,932

1,065

867

Enbridge Energy Partners, L.P.2
2022
2,493

1,044

1,449

Enbridge Gas Distribution Inc.
2019-2020
1,018

760

258

Enbridge Pipelines Inc.
2020
3,000

2,200

800

Spectra Energy Partners, LP3
2022
3,414

2,065

1,349

Union Gas Limited
2021
700

275

425

Total committed credit facilities
 
18,308

9,417

8,891

1
Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
2
Includes $253 million (US$185 million) of facilities that expire in 2020.
3
Includes $459 million (US$336 million) of facilities that expire in 2021.

Enbridge terminated a US$650 million credit facility, which was scheduled to mature in 2019, and repaid drawn amounts. In addition, an unutilized Enbridge US$100 million credit facility expired.

Enbridge (U.S.) Inc. terminated an unutilized US$950 million credit facility, which was scheduled to mature in 2019. In addition, Enbridge (U.S.) Inc. terminated a US$500 million credit facility, which was scheduled to mature in 2019, and repaid drawn amounts.

An unutilized EEP US$625 million credit facility matured on December 31, 2018.

Enbridge Income Fund substantially terminated its $1,500 million credit facility, which was scheduled to mature in 2020, and repaid drawn amounts.

Westcoast Energy Inc. terminated an unutilized $400 million credit facility, which was scheduled to mature in 2021.

On February 7, 2019 and February 8, 2019, we terminated certain Canadian and United States dollar credit facilities, including facilities held by Enbridge, Union Gas, EEP and SEP. We also increased existing facilities or obtained new facilities to replace the terminated ones under Enbridge, Enbridge (U.S.) Inc. and EGI. As a result, our total credit facility availability increased by approximately $390 million Canadian dollar equivalent, when translated using the year end December 31, 2018 spot rate.


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In addition to the committed credit facilities noted above, we have $807 million of uncommitted demand facilities, of which $548 million were unutilized as at December 31, 2018. As at December 31, 2017, we had $792 million of uncommitted credit facilities, of which $518 million were unutilized.
 
Our net available liquidity of $9,409 million at December 31, 2018 was inclusive of $518 million of unrestricted cash and cash equivalents as reported on the Consolidated Statements of Financial Position.
 
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2018, we were in compliance with all debt covenants and expect to continue to comply with such covenants.
 
Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled us to manage our credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to total capital. As at December 31, 2018, our debt capitalization ratio was 46.8% compared with 48.3% as at December 31, 2017.
 
During 2018, our credit ratings were affirmed as follows:
DBRS Limited confirmed our issuer rating and medium-term notes and unsecured debentures rating of BBB (high), fixed-to-floating subordinated notes rating of BBB (low), preference share rating of Pfd-3 (high) and commercial paper rating of R-2 (high), all with stable outlooks.
Standard & Poor’s Rating Services (S&P) affirmed our corporate credit rating and senior unsecured debt rating of BBB+, preference share rating of P-2 (low) and commercial paper rating of A-1 (low), and reaffirmed a stable outlook. S&P also affirmed our global overall short-term rating of A-2.
Fitch Rating services affirmed long-term issuer default rating and senior unsecured debt rating of BBB+, preference share rating of BBB-, junior subordinated note rating of BBB-, and short-term and commercial paper rating of F2 with a stable rating outlook.
On January 25, 2019 Moody’s Investor Services, Inc. upgraded our issuer and senior unsecured ratings from Baa3 to Baa2 with outlook revised to positive, upgraded our subordinated rating from Ba2 to Ba1, preference share rating from Ba2 to Ba1 and the commercial paper rating for Enbridge (U.S.) Inc. from P-3 to P-2.
 
We invest surplus cash in short-term investment grade money market instruments with highly creditworthy counterparties. Short-term investments were $76 million as at December 31, 2018 compared with $70 million as at December 31, 2017.

There are no material restrictions on our cash. Total restricted cash of $119 million, as reported on the Consolidated Statements of Financial Position, includes EGD's and Union Gas’ receipt of cash from the Government of Ontario to fund its Green Investment Fund program. In addition, our restricted cash includes cash collateral and amounts received in respect of specific shipper commitments. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us.

Excluding current maturities of long-term debt, at December 31, 2018 and 2017 we had a negative working capital position of $3,024 million and $2,538 million, respectively. In both periods, the major contributing factor to the negative working capital position was the ongoing funding of our growth capital program.
 
To address this negative working capital position, we maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due. As at December 31, 2018 and 2017, our net available liquidity totaled $9,409 million and

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$12,959 million, respectively, on a consolidated basis. It is anticipated that any current maturities of long-term debt will be refinanced upon maturity.
 
SOURCES AND USES OF CASH
December 31,
2018

2017

2016

(millions of Canadian dollars)
 

 

 

Operating activities
10,502

6,658

5,205

Investing activities
(3,017
)
(11,037
)
(5,152
)
Financing activities
(7,503
)
3,476

840

Effect of translation of foreign denominated cash and cash equivalents
68

(72
)
(19
)
Net increase/(decrease) in cash and cash equivalents and restricted cash
50

(975
)
874

 
Significant sources and uses of cash for the years ended December 31, 2018 and 2017 are summarized below:
 
Operating Activities
2018
The increase in cash flow delivered by operations in 2018 is a reflection of the positive operating factors discussed under Results of Operations.
Changes in operating assets and liabilities increased to a positive $915 million from a negative $338 million for the years ended December 31, 2018 and 2017, respectively. Our operating assets and liabilities fluctuate in the normal course due to various factors including fluctuations in commodity prices and activity levels within the Energy Services and Gas Distribution segments, the timing of tax payments, as well as timing of cash receipts and payments.

2017
The growth in cash flow delivered by operations in 2017 is a reflection of the positive operating factors discussed under Results of Operations, which included contributions from new assets of approximately $2,574 million following the completion of the Merger Transaction.
For the year ended, partially offsetting the increase in cash flows from operating activities are transaction costs in connection with the Merger Transaction, as well as employee severance costs in relation to our enterprise-wide reduction of workforce.
Changes in operating assets and liabilities increased to $338 million from $368 million for the years ended December 31, 2017 and 2016, respectively, reflected negative working capital in each of those years. Our operating assets and liabilities fluctuate in the normal course due to various factors including fluctuations in commodity prices and activity levels within the Energy Services and Gas Distribution segments, the timing of tax payments, as well as timing of cash receipts and payments.

Investing Activities
We continue with the execution of our growth capital program which is further described in Growth Projects – Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.
 
A summary of additions to property, plant and equipment for the years ended December 31, 2018, 2017 and 2016 is set out below:

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Year ended December 31,
2018

2017

2016

(millions of Canadian dollars)
 

 

 

Liquids Pipelines
3,102

2,797

3,956

Gas Transmission and Midstream
2,578

3,883

176

Gas Distribution
1,066

1,177

713

Green Power and Transmission
33

321

251

Energy Services

1


Eliminations and Other
27

108

32

Total capital expenditures
6,806

8,287

5,128

 
2018
The decrease in cash used in investing activities in 2018 was primarily attributable to proceeds from asset dispositions of $4,452 million compared with $628 million in 2017. This increase primarily reflected the sale of MOLP, international renewable assets and the provincially regulated portion of our Canadian Natural Gas Gathering and Processing Businesses assets. Please see Financing Activities below for further details on the use of these proceeds.
Further contributing to the decrease in cash used in investing activities was activity in 2017 that was not present in 2018, relating primarily to the acquisition of an interest in the Bakken Pipeline System.
We are continuing with the execution of our growth capital program which is further described in Growth Projects - Commercially Secured Projects. Capital expenditures of $6,806 million in 2018 compared with $8,287 million in 2017 reflected the timing of projects approvals, construction and in-service dates which impacts the timing of cash requirements.

2017
The increase in cash used in investing activities was primarily attributable to capital expenditures of $8,287 million compared with $5,128 million for the comparable period, which include capital expenditures on assets and growth projects acquired through the Merger Transaction, and increased investment in equity investments. During the first half of 2017, we paid cash consideration of $2.0 billion (US $1.5 billion) for the acquisition of an interest in the Bakken Pipeline System. In addition, we also made an equity investment of $0.5 billion in connection with our 50% interest in the Hohe See Offshore Wind Project.
The above increase in cash usage was partially offset by cash acquired in the Merger Transaction in the first quarter of 2017, proceeds from the disposition of the Ozark Pipeline, Sandpiper and Olympic Pipeline in 2017.

Financing Activities
2018
The increase in net cash used in financing activities resulted from the following factors:

Repayments of maturing term notes and credits facilities, and a decrease in long-term debt issued in 2018 when compared to 2017.
During 2018, we sold an interest in our Canadian and US renewable assets to the CPPIB. The proceeds of these dispositions and the dispositions of MOLP, the provincially regulated portion of our Canadian Natural Gas Gathering and Processing Businesses assets and international renewable assets discussed in Investing Activities above, were primarily used to repay maturing term notes and credit facilities, while proceeds from hybrid securities issued during the first half of 2018 were primarily used to repay credit facilities and to repurchase or redeem Spectra Energy Capital, LLC’s outstanding senior unsecured notes.
Cash from financing activities further decreased as a result of decreased contributions from noncontrolling interests and redeemable noncontrolling interests. Noncontrolling interest contributions received in 2017 related to completed projects for which there were no contributions received from noncontrolling interests in 2018. In April 2017, contributions from redeemable

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noncontrolling interests were received from a secondary public offering attributable to our holdings in ENF. There were no similar offerings in 2018.
Our common share dividend payments increased in the year ended 2018, primarily due to the increase in the common share dividend rate in the first quarter of 2018, as well as an increase in the number of common shares outstanding as a result of common shares issued in connection with the Merger Transaction and the issuance of approximately 33 million common shares in December 2017 in a private placement offering.

2017
The increase in net cash generated from financing activities resulted from the following factors:

We issued a series of medium term fixed and floating rate notes, the proceeds of which were used to repay maturing term notes and credit facilities and to finance growth capital programs. For the year ended 2017, proceeds from term note issuances were primarily used to repay credit facilities and redeem tender offers for Spectra Energy’s outstanding senior unsecured notes as discussed in Liquidity and Capital Resources - Capital Market Access.
The change in cash generated from financing activities reflected overall higher cash contributions from redeemable noncontrolling interests of $1,178 million compared with $591 million in the comparable period attributable to our holdings in ENF equity. Cash contributions were also higher for noncontrolling interests, which now include noncontrolling interests acquired through the Merger Transaction, which is more than offset by the increase in distributions to noncontrolling interests. The increase in distributions to noncontrolling interests was primarily attributable to the acquired assets, which were partially offset by the decrease in distributions resulting from the EEP strategic restructuring discussed under United States Sponsored Vehicle Strategy.
Cash provided from financing activities further increased as we completed the issuance of 33.5 million common shares for gross proceeds of approximately $1.5 billion along with the issuance of 4 million preferred shares for gross proceeds of $0.5 billion.
For the year ended 2017, the above increases in cash were partially offset by $227 million paid to acquire all of the outstanding publicly-held common units of MEP during the second quarter of 2017, as well as higher cash received from the issuance of common shares in the first quarter of 2016, as a result of the issuance of 56 million common shares in March 2016.
Finally, our common share dividend payments increased in the first half of 2017, primarily due to the increase in the common share dividend rate effective March 2017, as well as higher number of common shares outstanding as a result of the issuance of approximately 75 million common shares in 2016 and 691 million common shares issued in connection with the Merger Transaction. In addition, we paid $414 million in common share dividends to the shareholders of Spectra Energy. These dividends were declared before the closing of the Merger Transaction but were paid after the closing of the Merger Transaction.

Preference Share Issuances
Since July 2011, we have issued 315 million preference shares for gross proceeds of approximately $7.9 billion with the following characteristics.

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Gross Proceeds
Dividend Rate

Dividend1,7

Per Share
Base
Redemption
Value2
Redemption
and Conversion
Option Date2,3

Right to
Convert
Into3,4

(Canadian dollars, unless otherwise stated)
 

 
 

 

Series A
$125 million
5.50
%
$1.37500
$25


Series B
$457 million
3.42
%
$0.85360
$25
June 1, 2022

Series C

Series C5
$43 million
3-month treasury bill plus 2.40%


$25
June 1, 2022

Series B

Series D6
$450 million
4.46
%
$1.11500
$25
March 1, 2023

Series E

Series F6
$500 million
4.69
%
$1.17225
$25
June 1, 2023

Series G

Series H6
$350 million
4.38
%
$1.09400
$25
September 1, 2023

Series I

Series J
US$200 million
4.89
%
US$1.22160
US$25
June 1, 2022

Series K

Series L
US$400 million
4.96
%
US$1.23972
US$25
September 1, 2022

Series M

Series N6
$450 million
5.09
%
$1.27150
$25
December 1, 2023

Series O

Series P
$400 million
4.00
%
$1.00000
$25
March 1, 2019

Series Q

Series R
$400 million
4.00
%
$1.00000
$25
June 1, 2019

Series S

Series 16
US$400 million
5.95
%
US$1.48728
US$25
June 1, 2023

Series 2

Series 3
$600 million
4.00
%
$1.00000
$25
September 1, 2019

Series 4

Series 5
US$200 million
4.40
%
US$1.10000
US$25
March 1, 2019

Series 6

Series 7
$250 million
4.40
%
$1.10000
$25
March 1, 2019

Series 8

Series 9
$275 million
4.40
%
$1.10000
$25
December 1, 2019

Series 10

Series 11
$500 million
4.40
%
$1.10000
$25
March 1, 2020

Series 12

Series 13
$350 million
4.40
%
$1.10000
$25
June 1, 2020

Series 14

Series 15
$275 million
4.40
%
$1.10000
$25
September 1, 2020

Series 16

Series 17
$750 million
5.15
%
$1.28750
$25
March 1, 2022

Series 18

Series 19
$500 million
4.90
%
$1.22500
$25
March 1, 2023

Series 20

1
The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this feature.
2
Preference Shares, Series A may be redeemed any time at our option. For all other series of Preference Shares, we may, at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.
3
The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value.
4
With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x 90 day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US$25 x (number of days in quarter/365) x three-month United States Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6).
5
The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.22685 from $0.20342 on March 1, 2018, was increased to $0.22748 from $0.22685 on June 1, 2018, was increased to $0.23934 from $0.22748 on September 1, 2018 and was increased to $0.25459 from $0.23934 on December 1, 2018, due to reset on a quarterly basis following the issuance thereof.
6
No Series D, F, H, N, or 1 Preference shares were converted on the March 1, 2018, June 1, 2018, September 1, 2018, December 1, 2018 or June 1, 2018 conversion option dates, respectively. However, the quarterly dividend amounts for Series D, F, H, N, and 1, were reset to $0.27875 from $0.25000 on March 1, 2018, $0.29306 from $0.25000 on June 1, 2018, $0.27350 from $0.25000 on September 1, 2018, $0.31788 from $0.25000 on December 1, 2018 and US$0.37182 from US$0.25000 on June 1, 2018, respectively, due to reset on every fifth anniversary thereafter.
7
For dividends declared, see Liquidity and Capital Resources – Sources and Uses of Cash – Dividend Reinvestment and Share Purchase Plan.

Common Share Issuances
In the fourth quarter of 2018, we completed the issuance of 297 million common shares with a value of $12.7 billion in connection with the Sponsored Vehicles buy-in. For further information refer to Simplification of Corporate Structure and Item 8. Financial Statements and Supplementary Data - Note 21. Share Capital.


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On December 7, 2017, we completed the issuance of 33.5 million common shares for gross proceeds of approximately $1.5 billion. The proceeds were used to reduce short-term indebtedness pending reinvestment in secured capital projects.

On February 27, 2017, we completed the issuance of 691 million common shares with a value of $37.4 billion in exchange for shares of Spectra Energy in connection with the Merger Transaction. For further information, refer to Item 8. Financial Statements and Supplementary Data - Note 8. Acquisitions and Dispositions.

Dividend Reinvestment and Share Purchase Plan
On November 2, 2018, we announced the suspension of our Dividend Reinvestment and Share Purchase Plan (DRIP), effective immediately. Prior to the announcement, our shareholders were able to participate in the DRIP, which enabled participants to reinvest their dividends in our common shares at a 2% discount to market price and to make additional optional cash payments to purchase common shares at the market price, free of brokerage or other charges.

As a result of the announcement, shareholders only received dividends in cash effective with the dividend paid on December 1, 2018, to shareholders of record on November 15, 2018. If we elect to reinstate the DRIP in the future, the shareholders that were enrolled in the DRIP at the time of suspension and remain enrolled at the time of its reinstatement will automatically resume participation in the DRIP.

For the years ended December 31, 2018 and 2017, total dividends paid were $4,661 million and $3,562 million, respectively, of which $3,480 million and $2,336 million, respectively, were paid in cash and reflected in financing activities. The remaining $1,181 million and $1,226 million, respectively, of dividends paid were reinvested pursuant to the DRIP and resulted in the issuance of common shares rather than a cash payment. In addition to amounts paid in cash and reflected in financing activities for the year ended December 31, 2017, were $414 million in dividends declared to Spectra Energy shareholders prior to the Merger Transaction that were paid after the Merger Transaction.

Our Board of Directors has declared the following quarterly dividends. All dividends are payable on March 1, 2019 to shareholders of record on February 15, 2019.
Common Shares1

$0.73800

Preference Shares, Series A

$0.34375

Preference Shares, Series B

$0.21340

Preference Shares, Series C2

$0.25459

Preference Shares, Series D3

$0.27875

Preference Shares, Series F4

$0.29306

Preference Shares, Series H5

$0.27350

Preference Shares, Series J

US$0.30540

Preference Shares, Series L

US$0.30993

Preference Shares, Series N6

$0.31788

Preference Shares, Series P

$0.25000

Preference Shares, Series R

$0.25000

Preference Shares, Series 17

US$0.37182

Preference Shares, Series 3

$0.25000

Preference Shares, Series 5

US$0.27500

Preference Shares, Series 7

$0.27500

Preference Shares, Series 9

$0.27500

Preference Shares, Series 11

$0.27500

Preference Shares, Series 13

$0.27500

Preference Shares, Series 15

$0.27500

Preference Shares, Series 17

$0.32188

Preference Shares, Series 198

$0.30625

1 The quarterly dividend per common share was increased 10% to $0.73800 from $0.67100, effective March 1, 2019.

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2 
The floating dividend on the Series C Preference Shares is reset each quarter. The quarterly dividend amount of Series C increased to $0.22685 from $0.20342 on March 1, 2018, increased to $0.22748 from $0.22685 on June 1, 2018, increased to $0.23934 from $0.22748 on September 1, 2018 and increased to $0.25459 from $0.23934 on December 1, 2018.
3 
The quarterly dividend amount of Series D increased to $0.27875 from $0.25000 on March 1, 2018, due to the reset of the annual dividend on every fifth anniversary of the date of issuance of the Series D Preference Shares.
4 The quarterly dividend amount of Series F increased to $0.29306 from $0.25000 on June 1, 2018, due to the reset of the annual dividend on every fifth anniversary of the date of issuance of the Series F Preference Shares.
5 The quarterly dividend amount of Series H increased to $0.27350 from $0.25000 on September 1, 2018, due to the reset of the annual dividend on every fifth anniversary of the date of issuance of the Series H Preference Shares.
6 The quarterly dividend amount of Series N increased to $0.31788 from $0.25000 on December 1, 2018, due to the reset of the annual dividend on every fifth anniversary of the date of issuance of the Series N Preference Shares.
7 The quarterly dividend amount of Series 1 increased to US$0.37182 from US$0.25000 on June 1, 2018, due to the reset of the annual dividend on every fifth anniversary of the date of issuance of the Series 1 Preference Shares.
8 The quarterly dividend amount of Series 19 increased from the first dividend of $0.26850 payable on March 1, 2018 to the regular quarterly dividend of $0.30625, effective June 1, 2018.

OFF-BALANCE SHEET ARRANGEMENTS
We enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. See Item 8. Financial Statements and Supplementary Data - Note 30 Guarantees for further discussion of guarantee arrangements.

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

We do not have material off-balance sheet financing entities or structures, except for normal operating lease arrangements, guarantee arrangements and financings entered into by our equity investments. For additional information on these commitments, see Item 8. Financial Statements and Supplementary Data - Note 29. Commitments and Contingencies and Note 30. Guarantees.

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



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CONTRACTUAL OBLIGATIONS
Payments due under contractual obligations over the next five years and thereafter are as follows:
As at December 31, 2018
Total

Less than
1 year

1-3 years

3-5 years

After
5 years

(millions of Canadian dollars)
 

 

 

 

 

Annual debt maturities1
62,967

3,255

11,651

10,534

37,527

Interest obligations2
30,236