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•	Strategic positioning - between key supply basins with large, growing demand markets;

•	Strong commercial underpinnings - long-term contracts, established customers, strong risk-adjusted returns; and

•	Organic growth opportunities - the ability to create value by extending, expanding, repurposing, reconfiguring and replacing assets already in the ground.

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•	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.

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•	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.

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1	Our Consolidated Statements of Earnings and Consolidated Statements of Financial Position data reflect the following acquisitions, dispositions and impairment:

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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•	Liquids Pipelines also includes results from the operation of the Express-Platte System;

•	Gas Transmission and Midstream also includes Spectra Energy’s United States Storage and Transmission Assets, Canadian Pipeline & Field Services, Canadian Gas Transmission and Midstream and Maritimes & Northeast U.S. and Canada businesses, as well as the results of the Company’s 50% interest in DCP Midstream, LLC (DCP Midstream); and

•	Gas Distribution also includes results from the operation of Union Gas Limited (Union Gas).

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•	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 7. Acquisitions and Dispositions;

•	employee severance and restructuring costs of $354 million ($273 million after-tax attributable to us) in 2017, compared with $82 million in the corresponding 2016 period, related to a corporate reorganization initiative and the Merger Transaction, refer to Merger with Spectra Energy;

•	project development and transaction costs of $205 million ($155 after-tax attributable to us) in 2017, compared with $86 million in the corresponding 2016 period, related to the Merger Transaction, refer to Merger with Spectra Energy;

•	the absence 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, as discussed below; 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 24. 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 $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 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, as discussed below.

•	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;

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•	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.

•	a gain of $850 million ($520 million after-tax attributable to us) within the Liquids Pipelines segment related to the disposition of the South Prairie Region assets in December 2016;

•	a non-cash, unrealized derivative fair value gain of $543 million in 2016, compared with a $2,017 million unrealized derivative fair value loss in the corresponding 2015 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 price risks;

•

the absence of a goodwill impairment charge of $440 million ($167 million after-tax attributable to us) recognized in the second quarter of 2015 related to EEP’s natural gas and natural gas liquids (NGL) businesses as a result of the prolonged decline in commodity prices which reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL pipelines and processing systems; partially offset by

•	an impairment charge of $1,004 million ($81 million after-tax attributable to us) in 2016, including related project costs, on EEP's Sandpiper Project resulting from the withdrawal of regulatory applications for the project in September 2016 that were pending with the Minnesota Public Utilities Commission (MNPUC);

•	an impairment charge of $373 million ($272 million after-tax attributable to us) related to the Northern Gateway Project recorded in the fourth quarter of 2016, after the Canadian Federal Government directed the National Energy Board (NEB) to dismiss our Northern Gateway Project application and rescind the Certificates of Public Convenience and Necessity for the project; and

•	an impairment charge of $184 million ($108 million after-tax attributable to us) recorded in 2016 related to our 75% joint venture interest in Eddystone Rail, located in the Philadelphia, Pennsylvania area. Demand for Eddystone Rail services declined as a result of a significant decrease in Bakken crude oil and West Africa/Brent crude oil and increased competition in the region.

•	strong contributions from our Liquids Pipelines segment which benefited from a number of new assets that were placed into service in 2015;

•	throughput growth period over period on the Canadian Mainline, Lakehead Pipeline System (Lakehead System) and Regional Oil Sands System primarily due to strong oil sands production growth in western Canada enabled by completed pipeline expansion projects;

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•	contributions from the United States Gulf Coast and Mid-Continent systems in 2016, attributable to increased transportation revenues mainly resulting from an increase in the level of committed take-or-pay volumes on the Flanagan South Pipeline (Flanagan South);

•	contributions from Enbridge Offshore Pipelines' Heidelberg Oil Pipeline (Heidelberg Pipeline) which was placed into service in January 2016 and Canadian Gas Transmission and Midstream’s Tupper Main and Tupper West gas plants (the Tupper Plants) which were acquired on April 1, 2016; partially offset by

•	higher earnings attributable to noncontrolling interests and redeemable noncontrolling interests in 2016 compared with 2015 driven by stronger operating performance at EEP as a result of stronger contributions from its liquids business;

•	the impact of extreme wildfires in northeastern Alberta during the second quarter of 2016 which led to a temporary shutdown of certain of our upstream pipelines and terminal facilities resulting in a disruption of service on our Regional Oil Sands System with corresponding impacts into and out of our downstream pipelines, including Canadian Mainline and the Lakehead System;

•	a combination of a lower average International Joint Tariff (IJT) Residual Benchmark Toll and a lower foreign exchange hedge rate period over period used to convert Canadian Mainline United States dollar toll revenues to Canadian dollars;

•	the performance of the United States portion of the Bakken Pipeline System where contributions decreased period over period primarily due to a lower surcharge on tolls subject to annual adjustment;

•	lower contributions in 2016 from EEP’s Berthold rail facility as a result of declining volumes on expiration of contracts;

•	the compression of certain crude oil location and quality differentials and the impact of a weaker NGL market; and

•	depreciation and amortization expense increased period over period primarily as a result of a significant number of new assets placed into service in 2016.

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•	a non-cash, unrealized gain of $875 million in 2017 compared with $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 of an impairment charge of $1,004 million recorded in 2016, including related project costs, on EEP's Sandpiper Project resulting from the withdrawal of the regulatory applications in September 2016 that were pending with the MNPUC;

•	the absence of an impairment charge of $373 million 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 of an impairment charge of $184 million recorded in 2016 related to our 75% joint venture interest in Eddystone Rail attributable to market conditions which impacted volumes at the rail facility;

•	a gain of $72 million on sale of pipe partially offset by project wind-down costs related to EEP’s Sandpiper Project; partially offset by

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•	the absence of a gain of $850 million recorded in 2016 related to the sale of non-core South Prairie Region assets.

•	a lower contribution of $46 million 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;

•	a lower contribution of $76 million resulting from the sale of the South Prairie Region assets in December 2016;

•	higher 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;

•	the unfavorable effect of translating United States dollar EBITDA at a lower United States to Canadian dollar average exchange rate (Average Exchange Rate) as compared with 2016, inclusive of the impact of settlements under our foreign exchange hedging program; partially offset by

•	contributions of 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; and

•	higher Canadian Mainline and Lakehead System throughput period over period resulting from capacity optimization initiatives.

•	a non-cash, unrealized gain of $474 million in 2016 compared with an unrealized loss of $1,500 million in 2015 reflecting net fair value gains and losses on derivative financial instruments used to manage foreign exchange and commodity price risks;

•	a gain of $850 million in 2016 related to the sale of non-core South Prairie Region assets;

•	the absence of an impairment charge of $86 million recorded in 2015 related to EEP's Berthold rail facility due to contracts that were not renewed beyond 2016;

•	hydrostatic testing recoveries of $15 million in 2016 compared with charges of $72 million in 2015; partially offset by

•	an impairment charge of $1,004 million in 2016, including related project costs, on EEP's Sandpiper Project resulting from the withdrawal of the regulatory applications in September 2016 that were pending with the MNPUC;

•	an impairment charge of $373 million 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;

•	an impairment charge of $184 million in 2016 related to our 75% joint venture interest in Eddystone Rail attributable to market conditions which impacted volumes at the rail facility; and

•	the absence of a gain of $91 million recorded in 2015 related to the sale of non-core assets.

•	higher throughput period over period resulting from strong oil sands production in western Canada enabled by pipeline capacity expansion projects placed into service in 2015;

•	increased transportation revenues in 2016 resulting from an increase in the level of committed take-or-pay volumes on Flanagan South;

•	the favorable effect of translating United States dollar earnings at a higher Average Exchange Rate in 2016, inclusive of the impact of settlements under our foreign exchange hedging program; partially offset by

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•	the impact of extreme wildfires in northeastern Alberta during the second quarter of 2016 which led to a temporary shutdown of certain of our upstream pipelines and terminal facilities resulting in a disruption of service.

1

The IJT Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil. Effective July 1, 2015, this toll increased from US$4.02 to US$4.07. Effective July 1, 2016, this toll decreased to US$4.05. Effective July 1, 2017, this toll increased to US$4.07.

2

The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective April 1, 2015, the Lakehead System Local Toll decreased from US$2.49 to US$2.39 and effective July 1, 2015, this toll increased to US$2.44. Effective April 1, 2016, this toll increased to US$2.61 and effective July 1, 2016, this toll decreased to US$2.58. Effective April 1, 2017, this toll decreased to US$2.43.

3

The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll and the Lakehead System Local Toll. Effective April 1, 2015, this toll increased from US$1.53 to US$1.63. Effective April 1, 2016, this toll decreased to US$1.46, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2016, this toll increased to US$1.47. Effective April 1, 2017, this toll increased to US$1.62, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2017, this toll increased to US$1.64.

1	Average throughput volume represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada.

2	Average throughput volume represents mainline system deliveries to the United States midwest and eastern Canada.

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•	a loss of $4,391 million and related goodwill impairment of $102 million resulting from the classification of certain United States Midstream 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 7. Acquisitions and Dispositions; partially offset by

•	a non-cash, unrealized loss of $1 million in 2017 compared with $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.

•	lower earnings of $127 million period over period due to lower commodity prices which impacted production volume in areas served by some of our US Midstream assets; partially offset by

•	increased earnings of $19 million period over period from our Alliance joint venture due to favorable seasonal firm revenues that resulted from wider basis differentials;

•	increased earnings of $16 million due to a full year of contributions from the Tupper Plants that were acquired in April 2016;

•	increased fractionation margins of $45 million period over period driven by higher NGL prices and increased demand from our Aux Sable joint venture; and

•	increased earnings of $41 million period over period from our Offshore assets driven by higher volumes and higher earnings from certain joint venture pipelines.

•	the absence of a goodwill impairment charge of $440 million recorded in 2015 related to our United States natural gas and NGL businesses due to a prolonged decline in commodity prices which reduced producers' expected drilling programs and negatively impacted volumes on our natural gas and NGL systems; partially offset by

•	a non-cash, unrealized loss of $139 million in 2016 compared with $77 million in 2015 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.

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•	operational efficiencies achieved in 2016 on Alliance Pipeline due to lower operating costs;

•	contributions from the Heidelberg Pipeline which was placed into service in January 2016;

•	contributions from the Tupper Plants acquired in April 2016; partially offset by

•	unfavorable market conditions in 2016 resulting from lower volumes due to reduced drilling by producers on our United States Midstream assets.

•	a non-cash, unrealized gain of $16 million in 2017 compared with an unrealized loss of $6 million in 2016 arising from the change in the mark-to-market value of Noverco Inc.'s (Noverco) derivative financial instruments;

•	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 of other regulatory adjustments at Noverco of $17 million recorded in 2016.

•	warmer than normal weather experienced during 2016 which negatively impacted EBITDA by $18 million compared with colder than normal weather during 2015 of $15 million; partially offset by

•	other regulatory adjustments at Noverco of $17 million recorded in 2016 compared with $6 million in 2015.

•	higher distribution charges arising from growth in rate base, including customer growth in excess of expectations embedded in rates.

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•	the absence of an investment impairment loss of $13 million recorded in 2016; partially offset by

•	a $9 million loss that resulted from the sale of an investment.

•	stronger wind resources of $12 million at Canadian and United States wind farms period over period; and

•	contributions of $9 million from new United States wind projects placed into service in 2016 and 2017.

•	disruptions at certain eastern Canadian wind farms in the first quarter and fourth quarter of 2016 due to weather conditions which caused a higher degree of icing on wind turbine blades;

•	weaker wind resources experienced at certain facilities in Canada period over period; partially offset by

•	stronger wind resources at United States wind farms during the second half of 2016.

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•	a non-cash, unrealized loss of $200 million in 2017 compared with $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.

•	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.

•	a non-cash, unrealized loss of $205 million in 2016 compared with an unrealized gain of $264 million in 2015 reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and exposure to movements in commodity prices.

•	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 2016 which limited opportunities to generate profitable margins.

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•	project development and transaction costs of $197 million incurred in 2017 compared with $81 million in 2016 related to the Merger Transaction;

•	employee severance and restructuring costs of $292 million in 2017 compared with $92 million in

•	a non-cash, unrealized intercompany foreign exchange loss of $29 million in 2017 compared with $43 million in 2016 under our foreign exchange risk management program.

•	a realized loss of $173 million in 2017 compared with $281 million in 2016 related to settlements under our foreign exchange risk management program.

•	a non-cash, unrealized gain of $417 million in 2016 compared with an unrealized loss of $694 million in 2015 resulting from our foreign exchange hedging program; partially offset by

•	a non-cash, unrealized intercompany foreign exchange loss of $43 million in 2016 compared with a gain of $131 million in 2015;

•	project development and transaction costs of $81 million incurred in 2016 in relation to the Merger Transaction; and

•	employee severances costs of $92 million in 2016 compared with $47 million in 2015 related to a corporate reorganization initiative.

•	a realized loss of $281 million in 2016 compared with $203 million in 2015 related to settlements under our foreign exchange risk management program.

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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, 2017.

3	On February 15, 2017, EEP acquired an effective 27.6% interest in the Bakken Pipeline System for a purchase price of $2.0 billion (US$1.5 billion). On April 27, 2017, Enbridge entered into a joint funding arrangement with EEP whereby Enbridge owns 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System.

4	The Lakehead System Mainline Expansion project is funded 75% by Enbridge and 25% by EEP, and the project will be operated by EEP on a cost-of-service basis. The U.S. L3R Program is being funded 99% by Enbridge and 1% by EEP.

5	Project acquired as part of the Merger Transaction. For additional information, refer to Merger with Spectra Energy.

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Norlite Pipeline System (the Fund Group) - a diluent pipeline originating from our Stonefell Terminal and terminating at our Fort McMurray South facility, with a transfer line to Suncor's East Tank Farm. The project provides an initial capacity of approximately 218,000 bpd, with the potential to be further expanded to approximately 465,000 bpd with the addition of pump stations. The project was placed into commercial service on May 1, 2017.

•	Bakken Pipeline System (EEP) - a pipeline system that transports crude oil from the Bakken formation in North Dakota to markets in eastern PADD II, and the United States Gulf Coast. The system's initial capacity is approximately 470,000 bpd of crude oil and has the potential to be expanded to 570,000 bpd. The system was placed into service on June 1, 2017.

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Regional Oil Sands Optimization Project (the Fund Group) - the Athabasca Pipeline Twin portion of the project, which includes twinning of the southern section of the crude oil Athabasca Pipeline from Kirby Lake, Alberta to the crude oil hub at Hardisty, Alberta provides an initial capacity of approximately 450,000 bpd, with the potential to be further expanded to approximately 800,000 bpd. This portion of the project was placed into service on January 1, 2017. The Wood Buffalo Extension portion of the project includes a crude oil pipeline expansion between Cheecham, Alberta and Kirby Lake, Alberta that provides an initial capacity of approximately 635,000 bpd, with the potential to be further expanded to approximately 800,000 bpd. This portion of the project was placed into service on December 1, 2017.

•	JACOS Hangingstone Project (the Fund Group) - a crude oil pipeline connecting the Japan Canada Oil Sands Limited (JACOS) Hangingstone project site to our existing Cheecham Terminal that provides an initial capacity of approximately 40,000 bpd. The project was placed into service on August 29, 2017.

•	Lakehead System Mainline Expansion (EEP) - the remaining scope of the project includes the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois that will increase capacity from 950,000 bpd to 1,200,000 bpd, which was substantially completed in June of 2017. We currently anticipate an in-service date in the second half of 2019 for this phase to more closely align

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Canadian Line 3 Replacement Program (the Fund Group) - replacement of the existing Line 3 crude oil pipeline between Hardisty, Alberta and Gretna, Manitoba. The L3R Program will not provide an increase in the overall capacity of the mainline system, but will restore approximately 370,000 bpd and supports the safety and operational reliability of the overall system, enhances flexibility and will allow us to optimize throughput from western Canada into Superior, Wisconsin. The L3R Program is expected to achieve the original capacity of approximately 760,000 bpd. Construction commenced in early August 2017. For additional updates on the project, refer to Growth Projects - Regulatory Matters.

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United States Line 3 Replacement Program (EEP) - replacement of the existing Line 3 crude oil pipeline between Neche, North Dakota and Superior, Wisconsin. The U.S. L3R Program, along with the Canadian L3R Program discussed above, will support the safety and operational reliability of the mainline system, enhance system flexibility, and allow the Company and EEP to optimize throughput on the mainline. The L3R Program is expected to achieve the original capacity of approximately 760,000 bpd. Construction commenced on the Wisconsin portion of the U.S. L3R Program in late June 2017 and will be substantially complete in February 2018. For additional updates on the project, refer to Growth Projects - Regulatory Matters.

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Sabal Trail (SEP) - a natural gas pipeline connecting Alexander City, Alabama to the Central Florida Hub in Kissimmee, Florida that provides capacity of approximately 1.1 billion cubic feet per day (bcf/d) of new capacity to access onshore shale gas supplies once approved future expansions are completed. Facilities include a new 749-kilometer (465-mile) pipeline, laterals and various compressor stations. The project was placed into service on July 3, 2017.

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Access South, Adair Southwest and Lebanon Extension (SEP) - natural gas pipeline extensions connecting the Appalachian region of the United States to markets in the Midwest and Southeast regions of the United States. The combined projects provide an initial capacity of 622 million cubic feet per day (mmcf/d) of gas to customers in Ohio, Kentucky and Mississippi. The Lebanon extension was placed into service early, on August 1, 2017 and the majority of the Access and Adair portions of the project were placed in service in November 2017 with the final 20 mmcf/d expected to be placed in service in the first quarter of 2018.

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Atlantic Bridge (SEP) - expansion of SEP’s Algonquin Gas Transmission systems to transport 133 mmcf/d of natural gas to the New England Region. The expansion primarily consists of the replacement of a natural gas pipeline, meter station additions, compression additions in Connecticut, and a new compressor station in Massachusetts. The Connecticut portion of the project was placed into service in the fourth quarter of 2017. The remainder of the project is expected to be in-service during the fourth quarter of 2018.

•	NEXUS (SEP) - a natural gas pipeline system connecting SEP’s Texas Eastern pipeline system in Ohio to the Union Gas Dawn hub in Ontario, via Vector Pipeline L.P., that will provide capacity of up to approximately 1.5 bcf/d. The project received a Notice to Proceed from the Federal Energy Regulatory Commission (FERC) in August 2017 and construction activities have commenced.

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Reliability and Maintainability Project - a natural gas pipeline project designed to enhance the performance of the southern segment of the British Columbia Pipeline system to accommodate the increased base load on the system. The project involves 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. During 2017, six crossovers were placed into service.

•	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, which is being constructed by a third party. The project will help Mexico meet its growing gas fired electric generation needs by providing capacity of up to approximately 2.6 bcf/d.

•	Spruce Ridge Program - natural gas pipeline expansion of Westcoast Energy Inc.’s British Columbia Pipeline in northern British Columbia, 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.

•	T-South Expansion Program - 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.

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•	2017 Dawn-Parkway Expansion - the expansion of the existing Dawn-Parkway pipeline system, which provides transportation service from Dawn to the Greater Toronto Area, through the addition of new compressors at each of the Dawn, Lobo and Bright compressor stations in Ontario. The project provides additional capacity of approximately 419 mmcf/d and was placed into service in October 2017.

•	Panhandle Reinforcement Project - the expansion of the existing Panhandle pipeline from Dawn to the Dover transmission station in Chatham-Kent, Ontario. The project serves firm demand growth in southwestern Ontario and was placed into service in November 2017.

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Chapman Ranch Wind Project - a wind project that consists of 81 Acciona Windpower North America, LLC (Acciona) turbines located in Nueces County, Texas which generate approximately 249-MW of power and were placed into service on October 25, 2017. Acciona provides turbine operations and maintenance services under a five-year fixed-price contract with an option to extend. The project is backed by a 12-year power offtake agreement.

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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 when complete. 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 is currently in the commissioning phase.

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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.

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Gray Oak Pipeline Project - a 385,000 bpd pipeline system to provide producers and other shippers the opportunity to secure crude oil transportation from West Texas to the destination markets of Corpus Christi, Freeport, and Houston, Texas with connectivity to over 3 million bpd of refining capacity and multiple dock facilities capable of crude oil exports. The project is a joint development with Phillips 66 and would be placed into service during the second half of 2019 depending on shipper interest expressed in the recently closed open season.

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Gulf Coast Express Pipeline Project - a natural gas pipeline connecting the Waha, Texas area to Agua Dulce, Texas that will provide capacity up to approximately 1.7 bcf/d. The project is a joint development between our equity investment DCP Midstream, Kinder Morgan Texas Pipeline LLC and an affiliate of Targa Resources Corp, and is expected to be placed into service during the second half of 2019, subject to obtaining sufficient shipper commitments.

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Alliance Pipeline Expansion Project - Alliance Pipeline announced a non-binding request for expressions of interest for additional transportation service on the Alliance Pipeline Canada and Alliance Pipeline US systems. Alliance Pipeline continues to engage with interested parties and assess the addition of more compression facilities along the system in order to increase throughput capacity by up to 500 mmcf/d. The projected in-service date for the potential capacity expansion is the second half of 2021.

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Access Northeast - Access Northeast is a project that will bring affordable energy to New England consumers. Natural gas pipeline capacity scarcity and system reliability remains a primary issue for New England and one that must be resolved for the region to meet its energy supply needs. The project's partners continue to pursue a viable commercial and operational model to provide natural gas to the region.

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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 farms 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.

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1	Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.

2	Includes $135 million, $157 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively.

3	Includes $219 million (US$175 million) and $232 million (US$185 million) of commitments that expire in 2018 and 2020, respectively.

4	Includes $421 million (US$336 million) of commitments that expire in 2021.

5	Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction. For additional information, refer to Merger with Spectra Energy.

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•	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), and changed their rating outlook from under review with developing implications to stable.

•	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.

•	In June 2017, we obtained Fitch 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 December 22, 2017, Moody’s Investor Services, Inc. downgraded our issuer and senior unsecured ratings from Baa2 to Baa3, subordinated rating from Ba1 to Ba2, preference share rating from Ba1 to Ba2, commercial paper rating for Enbridge (U.S.) Inc. from P-2 to P-3, and changed the outlook on all of these ratings from negative to stable.

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•	The growth in cash flow delivered by operations in 2017 is a reflection of the positive operating factors discussed under Results of Operations, which primarily 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 to $314 million from $358 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.

•

The growth in cash flow delivered by operations in 2016 was a reflection of the positive operating factors discussed under Results of Operations, which primarily included stronger contributions from the Liquids Pipelines segment, partially offset by higher financing costs resulting from the incurrence of incremental debt to fund asset growth and the impact of refinancing construction debt with longer-term debt financing.

•

Changes in operating assets and liabilities included within operating activities were $358 million for the year ended December 31, 2016 compared with $645 million for the comparative 2015 year. 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, general variations in activity levels within our businesses, as well as timing of cash receipts and payments.

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•

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 Project and Olympic Pipeline in 2017.

•

The timing of projects approval, construction and in-service dates impacted the timing of cash requirements. For the year ended December 31, 2016, additions to property, plant and equipment resulted in cash expenditures of $5,128 million compared with $7,273 million for the year ended December 31, 2015. The year-over-year decrease reflected the successful completion of growth projects in 2015, including the Edmonton to Hardisty Expansion, Southern Access Extension and phases of the Eastern Access Program.

•

Also contributing to the decrease in year-over-year cash used in investing activities were proceeds received from disposition of assets. For the year ended December 31, 2016, proceeds from dispositions were $1,379 million compared with $146 million for the year ended December 31, 2015. The majority of the proceeds in 2016 related to the sale of the South Prairie Region assets completed in December 2016.

•	Partially offsetting the above factors was higher spending in 2016 for acquisitions. During the second quarter of 2016, we made an initial equity investment in and advanced an affiliate loan to acquire a 50% interest in a French offshore wind development company and fund the ongoing development costs of that company.

•

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

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•	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.

•	Our financing requirements decreased for the year ended December 31, 2016 compared with December 31, 2015, primarily reflecting lower expenditures on growth capital projects and the proceeds of asset sales. Our funding requirements are a reflection of the timing of various growth projects.

•

In 2016, our overall debt decreased by $149 million compared with an overall increase in debt of $3,663 million in 2015. The decrease was mainly due to lower debt requirements resulting from the timing of completion of various growth projects and other sources of funds, primarily the proceeds from our common share issuance in March 2016, which were partly utilized to reduce drawn credit facilities and outstanding commercial paper draws.

•	The increase in common share dividends paid in 2016 was attributable to the increase in the common share dividend rate effective March 2016 and a higher number of common shares outstanding primarily as a result of the common share issuance noted above.

•

Distributions to redeemable noncontrolling interests in the Fund Group increased during 2016 compared with the corresponding 2015 period mainly due to a higher per share distribution rate and a larger number of public shares outstanding in ENF. Higher distributions to noncontrolling interests in EEP reflected an increase to the per unit distribution in the first half of 2016 as well as the effects of a strengthening United States dollar versus the Canadian dollar.

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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

On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares based upon preference share holder elections under the terms of the Series B Preference Shares. The quarterly dividend amount for the Series B Preference Shares was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series B Preference Shares. The quarterly dividend amount for the Series C Preference Shares was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on December 1, 2017, due to reset on a quarterly basis following the issuance thereof.

6

On January 30, 2018, we announced that we do not intend to exercise our right to redeem our Series D Preference Shares on March 1, 2018. As a result, until February 14, 2018, the holders of such shares had the right to convert all or part of their Series D fixed rate Preference Shares on a one-for-one basis into Series E floating rate Preference Shares. As of February 14, 2018, less than the 1,000,000 Series D Preference Shares required to give effect to conversions into Series E Preference Shares were tendered for conversion. As a result, none of our outstanding Series D Preference Shares will be converted into Series E Preference Shares on March 1, 2018. However, on March 1, 2018, the quarterly dividend amount for the Series D Preference Shares will be increased to $0.27875 from $0.25000, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series D Preference Shares.

7

No Series J or Series L Preference Shares were converted on the June 1, 2017 and September 1, 2017 conversion option dates, respectively. However, the quarterly dividend amounts for the Series J and Series L Preference Shares were increased to US$0.30540 from US$0.25000 on June 1, 2017, and to US$0.30993 from US$0.25000 on September 1, 2017, respectively, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series J and Serles L Preference Shares.

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8	On December 11, 2017, 20 million Series 19 Preferred Shares, inclusive of 4 million Series 19 Preferred Shares issued on full exercise of the underwriters' option, were issued for gross proceeds of $500 million.

9	For dividends declared, see Liquidity and Capital Resources – Sources and Uses of Cash – Dividend Reinvestment and Share Purchase Plan.

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1	The quarterly dividend amount of Series B was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual dividend on every fifth anniversary of the date of issuance of the Series B Preference Shares.

2	The quarterly dividend amount of Series C was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on December 1, 2017, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.

3	The quarterly dividend amount of Series J was increased to US$0.30540 from US$0.25000 on June 1, 2017, due to the reset of the annual dividend on every fifth anniversary of the date of issuance of the Series J Preference Shares.

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1	Includes distributions for our ownership interest in EEP and distributions from direct ownership in its jointly funded projects.

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Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discount, debt issue costs and capital lease obligations. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above.

2	Excludes the debt issuance of US$800 million senior notes that occurred subsequent to December 31, 2017.

3	Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.

4	Includes land leases.

5	Assumes only required payments will be made into the pension plans in 2018. Contributions are made in accordance with independent actuarial valuations as at December 31, 2017. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.

6

Included within long-term contracts, in the table, above are contracts that we have signed for the purchase of services, pipe and other materials totaling $2,609 million which are expected to be paid over the next five years. Also consists of the following purchase obligations: gas transportation and storage contracts (EGD), firm capacity payments and gas purchase commitments (Spectra Energy), transportation, service and product purchase obligations (MEP), and power commitments (EEP).

7

We are unable to estimate deferred income taxes (Item 8. Financial Statements and supplementary data - Note 24. Income Taxes) since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year. We are also unable to estimate asset retirement obligations (Item 8. Financial Statements and supplementary data - Note 18. Asset Retirement Obligations), environmental liabilities (Item 8. Financial Statements and supplementary data - Note 28. Commitments and Contingencies) and hedges payable (Item 8. Financial Statements and supplementary data - Note 23. Risk Management and Financial Instruments) due to the uncertainty as to the amount and, or, timing of when cash payments will be required.

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•	Costs of providing service, including depreciation expense;

•	Allowed rate of return, including the equity component of the capital structure and related income taxes; and

•	Contract and volume throughput assumptions.

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•	A change in presentation in the Gas Distribution business related to payments to customers under the earnings sharing mechanism which are currently shown as an expense in the Consolidated Statements of Earnings. Under the new standard, these payments will be reflected as a reduction of revenue.

•	Estimates of variable consideration, required under the new standard for certain Liquids Pipelines, Gas Transmission and Midstream and Green Power and Transmission revenue contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts.

•

Non-cash consideration received in the form of a percentage of the products derived from processing natural gas in the Gas Transmission and Midstream business was previously accounted for as revenue when the commodity was sold to third parties. Under the new standard, the non-cash consideration will be accounted for as revenue when processing services are performed. The commodity will continue to be accounted for as revenue when it is subsequently sold to third parties. The impact of this change will be an increase in costs and revenues due to the recognition of this non-cash consideration.

•

Service fee revenue, from processing natural gas for certain contracts in the Gas Transmission and Midstream business whereby Enbridge purchases natural gas at the wellhead, then processes and subsequently sells the gas, was previously presented as revenue. Under the new standard, processing fees charged on natural gas purchased by Enbridge are presented as a reduction of commodity costs upon the transfer of control of the natural gas at the wellhead.

•	Revenue from certain contracts in the Gas Transmission and Midstream business that provide for Enbridge to process and sell customers’ natural gas and retain a percentage of the resulting processed natural gas and/or NGLs as payment for processing services rendered, commonly referred to as Percentage of Proceeds and Percentage of Liquids contracts, was previously

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•

Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIAC) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or negotiated. Under the new standard, negotiated CIACs are deemed to be advance payments for services and must be recognized as revenue when those future services are provided. Negotiated CIACs will be accounted for as deferred revenue and recognized over the term of the associated revenue contract.

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•	Cost of pension plan benefits provided in exchange for employee services rendered during the year;

•	Interest cost of pension plan obligations;

•	Expected return on pension plan assets;

•	Amortization of the prior service costs and amendments on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans; and

•	Amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans.

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•	A change in presentation in the Gas Distribution business related to payments to customers under the earnings sharing mechanism which are currently shown as an expense in the

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•	Estimates of variable consideration, required under the new standard for certain Liquids Pipelines, Gas Transmission and Midstream and Green Power and Transmission revenue contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts.

•

Non-cash consideration received in the form of a percentage of the products derived from processing natural gas in the Gas Transmission and Midstream business was previously accounted for as revenue when the commodity was sold to third parties. Under the new standard, the non-cash consideration will be accounted for as revenue when processing services are performed. The commodity will continue to be accounted for as revenue when it is subsequently sold to third parties. The impact of this change will be an increase in costs and revenues due to the recognition of this non-cash consideration.

•

Service fee revenue, from processing natural gas for certain contracts in the Gas Transmission and Midstream business whereby Enbridge purchases natural gas at the wellhead, then processes and subsequently sells the gas, was previously presented as revenue. Under the new standard, processing fees charged on natural gas purchased by Enbridge are presented as a reduction of commodity costs upon the transfer of control of the natural gas at the wellhead.

•

Revenue from certain contracts in the Gas Transmission and Midstream business that provide for Enbridge to process and sell customers’ natural gas and retain a percentage of the resulting processed natural gas and/or NGLs as payment for processing services rendered, commonly referred to as Percentage of Proceeds and Percentage of Liquids contracts, was previously presented on a gross basis whereby Enbridge recorded one hundred percent of the value of the natural gas and products sold as revenue, with the cost of the natural gas purchased recorded as commodity cost. Under the new standard only Enbridge’s share of the products retained and sold is presented as revenue and no commodity cost is recorded.

•

Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIAC) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or negotiated. Under the new standard, negotiated CIACs are deemed to be advance payments for services and must be recognized as revenue when those future services are provided. Negotiated CIACs will be accounted for as deferred revenue and recognized over the term of the associated revenue contract.

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1	Includes allowance for equity funds used during construction.

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1	Funds collected are included in Restricted long-term investments (Note 13).

2	Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation dated December 22, 2017.

3	Purchase gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD and Union Gas have been granted OEB approval to refund this balance to, or to collect this balance from, customers on a rolling 12-month basis via the Quarterly Rate Adjustment Mechanism process.

4	The balances are excluded from the rate base and do not earn an ROE.

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a)	Accounts receivable is comprised primarily of customer trade receivables and natural gas imbalances. As such, the fair value of accounts receivable approximates the net carrying value of $1,174 million. The gross amount due of $1,190 million, of which $16 million is not expected to be collected, is included in current assets.

b)

We have applied the valuation methodologies described in ASC 820 Fair Value Measurements and Disclosures, to value the property, plant and equipment purchased. The fair value of Spectra Energy’s rate-regulated property, plant and equipment was determined using a market participant perspective, which is their carrying amount. The fair value of the remaining non-regulated property, plant and equipment was determined primarily using variations of the income approach, which is based on the present value of the future after-tax cash flows attributable to each non-regulated asset. Some of the more significant assumptions inherent in the development of the values, from the perspective of a market participant, include, but are not limited to, the amount and timing of projected future cash flows (including revenue and profitability); the discount rate selected to measure the risks inherent in the future cash flows; the assessment of the asset’s life cycle; the competitive trends impacting the asset; and customer turnover.

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c)

Long-term investments represent Spectra Energy’s 50% equity investment in DCP Midstream, Gulfstream Natural Gas System, L.L.C., Nexus Gas Transmission, LLC (Nexus), Steckman Ridge LP, Islander East Pipeline Company, L.L.C., Southeast Supply Header L.L.C., and 20% equity interest in PennEast Pipeline Company LLC (PennEast). The fair value of these investments was determined using an income approach.

e)	Intangible assets primarily consist of customer relationships in the non-regulated business, which represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition, determined using the income approach. Intangible assets are amortized on a straight-line basis over their expected lives.

1	Represents customer relationships in the non-regulated business, which were capitalized upon acquisition.

2

Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership interest in Sabal Trail Transmission, LLC (Sabal Trail), as certain milestones of the project are met. Amortization of the intangible asset began on July 3, 2017, when Sabal Trail was placed into service (Note 12).

f)	The fair value of Spectra Energy’s noncontrolling interests includes approximately 78.4 million SEP common units outstanding to the public, valued at the February 24, 2017 closing price of US$44.88 per common unit on the NYSE, and units held by third parties in Maritimes & Northeast Pipeline, L.L.C., Sabal Trail and Algonquin Gas Transmission, L.L.C., valued based on the

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g)

We recorded $36.7 billion in goodwill, which is primarily related to expected synergies from the Merger Transaction. The goodwill balance recognized is not deductible for tax purposes. Factors that contributed to the goodwill include the opportunity to expand our natural gas pipelines segment, the potential for cost and supply chain optimization synergies, existing assembled assets and work force that cannot be duplicated at the same cost by a new entrant, franchise rights and other intangibles not separately identifiable because they are inextricably linked to the provision of regulated utility service and the enhanced scale and geographic diversity which provide greater optionality and platforms for future growth.

1	Merger Transaction costs of $180 million (after-tax $131 million) were excluded from earnings for the year ended December 31, 2017.

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1	At December 31, 2017, the maximum exposure to loss includes a guarantee by us for our respective share of the VIE’s borrowing on a bank credit facility.

2	At December 31, 2017, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $163 million held by us.

3	At December 31, 2017, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE.

4	At December 31, 2017, the maximum exposure to loss is limited to our equity investment as these companies are in operation and self-sustaining.

5	At December 31, 2017 the maximum exposure to loss is limited to our equity investment and the remaining expected contributions for each joint venture.

6	At December 31, 2017, the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE.

7	At December 31, 2017 the maximum exposure to loss includes the carrying value of an outstanding loan issued by us.

8	As at December 31, 2017, Eddystone Rail Company, LLC is a 100% owned subsidiary and therefore is no longer an unconsolidated VIE.

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1	On February 15, 2017, EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System) for a purchase price of $2 billion (US$1.5 billion). The Bakken Pipeline System was placed into service on June 1, 2017. For details regarding our funding arrangement, refer to Note 19 - Noncontrolling Interests.

2	Owns the Southern Access Extension Project.

3	Certain assets of the Alliance Pipeline are pledged as collateral to Alliance Pipeline lenders.

4	On February 27, 2017, we acquired Spectra Energy's interests in DCP Midstream, Gulfstream Natural Gas System, L.L.C, Nexus, PennEast, Southeast Supply Header L.L.C., Steckman Ridge LP and other equity investments as part of the Merger Transaction (Note 7).

5	On February 27, 2017, we acquired Spectra Energy's consolidated interest in Sabal Trail as part of the Merger Transaction (Note 7). On July 3, 2017, Sabal Trail was placed into service and the assets, liabilities, and noncontrolling interests were deconsolidated as at the in-service date.

6	On May 19, 2016, we acquired a 50% equity interest in Eolien Maritime France SAS.

7	On February 8, 2017, we acquired an effective 50% interest in EnBW Hohe See GmbH & Co. KG.

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1	2017 - US$4,700 million; 2016 - US$3,700 million.

2	2017 - $1,650 million and US$1,750 million; 2016 - US$750 million. For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal the three-month Bankers' Acceptance Rate or London Interbank Offered Rate (LIBOR) plus a margin.

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3	The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events.

4	2017 - $750 million and US$1,200 million; 2016 - $500 million and US$500 million. Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus a margin of 59 basis points or LIBOR plus a margin of 40 or 70 basis points.

5	2017 - $1,593 million and US$907 million; 2016 - $3,600 million and US$799 million.

6	Primarily capital lease obligations.

7	2016 - US$10 million.

8	2017 - US$391 million; 2016 - US$94 million.

9	2017 - US$5,050 million; 2016 - US$5,050 million.

10	2017 - US$400 million; 2016 - US$400 million. Carries an interest rate equal to the three-month LIBOR plus a margin of 379.75 basis points.

11	2017 - US$1,453 million; 2016 - US$1,658 million.

12	2017 - US$963 million; 2016 - US$1,000 million.

13	Included in medium-term notes is $100 million with a maturity date of 2112.

14	2017 - $1,080 million and US$286 million; 2016 - $750 million and US$210 million.

15	2017 - US$400 million; 2016 - US$400 million.

16	2016 - US$420 million.

17	Debt acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7).

18	2017 - US$1,329 million.

19	2017 - US$110 million.

20	2017 - US$5,740 million.

21	2017 - US$400 million. Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points.

22	2017 - US$2,254 million.

23	Primarily debt discount and debt issue costs.

24	Weighted average interest rate - 1.4%; 2016 - 0.8%.

1	Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.

2	Includes $135 million, $157 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively.

3	Includes $219 million (US$175 million) and $232 million (US$185 million) of commitments that expire in 2018 and 2020, respectively.

4	Includes $421 million (US$336 million) of commitments that expire in 2021.

5	Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7).

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1	Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points.

2	Carries an interest rate equal to the three-month LIBOR plus 70 basis points.

3	Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.5%. Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 342 basis points from year 10 to 30, and a margin of 417 basis points from year 30 to 60.

4	Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 5.4%. Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points from year 10 to 30, and a margin of 400 basis points from year 30 to 60.

5	Carries an interest rate equal to the three-month LIBOR plus 40 basis points.

6	Matures in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.0%. Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 389 basis points from year 10 to 30, and a margin of 464 basis points from year 30 to 60.

7	Carries an interest rate equal to the three-month LIBOR plus 70 basis points.

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1

On July 7, 2017 and September 8, 2017, Enbridge and Spectra Energy Capital, LLC (Spectra Capital) completed a cash tender offer for and follow-up redemption of Spectra Capital’s outstanding 8.0% senior unsecured notes due 2019. The aggregate principal amount tendered and redeemed was US$500 million. Spectra Capital paid the consenting note holders an aggregate cash consideration of US$581 million.

2

On July 13, 2017, pursuant to a cash tender offer, Spectra Capital purchased a portion of the principal amount of its outstanding senior unsecured notes carrying interest rates ranging from 3.3% to 7.5%, with maturities ranging from one to 21 years. The principal amount tendered and accepted was US$761 million. Spectra Capital paid the consenting note holders an aggregate cash consideration of US$857 million.

3	The loss on debt extinguishment of $50 million (US$38 million), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.

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1	Represents the 88.3% of the listed shares of Enbridge Energy Management, L.L.C. (EEM) not held by us as at December 31, 2017 and 2016.

2	Represents the 68.2% and 80.2% interest in EEP held by public unitholders as well as interests of third parties in subsidiaries of EEP as at December 31, 2017 and 2016, respectively.

3	Represents the four million cumulative redeemable preferred shares held by third parties in EGD as at December 31, 2017 and 2016.

4	Represents the tax equity investors' interests in our Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind farms, which are accounted for using the HLBV method, with an additional 20.0% noncontrolling interest in each of the Magic Valley and Wildcat wind farms held by third parties as at December 31, 2017 and 2016.

5	Represents the 25.7% interest in SEP held by public unitholders as at December 31, 2017.

6	Represents the four million cumulative redeemable preferred shares held by third parties in Union Gas as at December 31, 2017.

7	Represents the 16.6 million cumulative redeemable preferred shares and 12 million cumulative first preferred shares as at December 31, 2017 held by third parties in Westcoast Energy Inc., and the 22.0% interest in Maritimes & Northeast Pipeline Limited Partnership held by third parties.

8	Represents noncontrolling interests resulting from the Merger Transaction (Note 7).

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1	These transactions occurred in December 2017, April 2016 and November 2015.

2	Concurrent with the public offerings, we subscribed for ENF common shares on a private placement basis to maintain our 19.9% ownership interest in ENF.

3	ENF used the proceeds from the common share issuances to purchase additional trust units of the Fund. We did not participate in these offerings, resulting in increases in redeemable noncontrolling interests (2017 - 53.6% to 56.5%; 2016 - 40.7% to 45.6%; 2015 - 34.3% to 40.7%).

4

The Fund used a portion of the proceeds from the trust unit issuances to purchase additional common units of ECT, and ECT used the proceeds to purchase additional Class A units of EIPLP, resulting in dilution losses for ECT. These dilution losses resulted in dilution losses for the Fund’s equity investment in ECT and the above-noted dilution gains/(losses) for redeemable noncontrolling interests and Additional paid-in capital.

5	For the years ended December 31, 2017, 2016 and 2015, ENF used cash in respect of reinvested dividends and option cash payments from its Dividend Reinvestment Plan (DRIP) to purchase 1.6 million, 1.3 million and nil Fund trust units, respectively, on behalf of the public.

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1

The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this feature.

2	Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we, may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.

3	The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value.

4

With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/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

On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares based upon preference share holder elections under the terms of the Series B Preference Shares. The quarterly dividend amount for the Series B Preference Shares was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series B Preference Shares. The quarterly dividend amount for the Series C Preference Shares was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on December 1, 2017, due to reset on a quarterly basis following the issuance thereof.

6

On January 30, 2018, we announced that we do not intend to exercise our right to redeem our Series D Preference Shares on March 1, 2018. As a result, until February 14, 2018, the holders of such shares had the right to convert all or part of their Series D fixed rate Preference Shares on a one-for-one basis into Series E floating rate Preference Shares. As of February 14, 2018, less than the 1,000,000 Series D Preference Shares required to give effect to conversions into Series E Preference Shares were tendered for conversion. As a result, none of our outstanding Series D Preference Shares will be converted into Series E Preference Shares on March 1, 2018. However, on March 1, 2018, the quarterly dividend amount for the Series D Preference Shares will be increased to $0.27875 from $0.25000, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series D Preference Shares.

7

No Series J or Series L Preference Shares were converted on the June 1, 2017 and September 1, 2017 conversion option dates, respectively. However, the quarterly dividend amounts for the Series J and Series L Preference Shares were increased to US$0.30540 from US$0.25000 on June 1, 2017, and to US$0.30993 from US$0.25000 on September 1, 2017, respectively, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series J and Serles L Preference Shares.

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1	The total intrinsic value of ISOs exercised during the years ended December 31, 2017, 2016 and 2015 was $62 million, $123 million and $126 million, respectively, and cash received on exercise was $17 million, $37 million and $43 million, respectively.

2	The total fair value of ISOs vested during the years ended December 31, 2017, 2016 and 2015 was $44 million, $36 million and $34 million, respectively.

1

Options granted to United States employees are based on NYSE prices. The option value and assumptions shown are based on a weighted average of the United States and the Canadian options. The fair values per option for the years ended December 31, 2017, 2016 and 2015 were $5.66, $7.01 and $6.22, respectively, for Canadian employees and US$5.72, US$6.60 and US$6.16, respectively, for United States employees.

2	The expected option term is six years based on historical exercise practice and three years for retirement eligible employees.

3	Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date.

4	The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.

5	The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields.

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1	The total amount paid during the years ended December 31, 2017, 2016 and 2015 for RSUs was $39 million, $56 million and $45 million, respectively.

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1	Reported within Interest expense in the Consolidated Statements of Earnings.

2	Reported within Commodity costs in the Consolidated Statements of Earnings.

3	Reported within Other income/(expense) in the Consolidated Statements of Earnings.

4	Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

5	These components are included in the computation of net benefit costs and are reported within Operating and administrative expense in the Consolidated Statements of Earnings.

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1	As at December 31, 2017, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2023 through 2025.

2	As at December 31, 2016, the average net purchase/(sell) of power was (4) MW/H for 2017 through 2025 with a high of 40 MW/H and a low of (43) MW/H.

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1	Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.

2	Reported within Interest expense in the Consolidated Statements of Earnings.

3	For the year ended December 31, 2017, includes settlements of $296 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt.

4	Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

5	Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

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1	For the respective annual periods, reported within Transportation and other services revenues (2017 - $800 million gain; 2016 - $497 million gain; 2015 - $1,383 million loss) and Other income/(expense) (2017 - $484 million gain; 2016 - $438 million gain; 2015 - $804 million loss) in the Consolidated Statements of Earnings.

2	Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.

3

For the respective annual periods, reported within Transportation and other services revenues (2017 - $104 million loss; 2016 - $52 million loss; 2015 - $328 million gain), Commodity sales (2017 - $90 million gain 2016 - $474 million loss; 2015 - $226 million loss), Commodity costs (2017 - $223 million loss; 2016 - $38 million gain; 2015 - $99 million gain) and Operating and administrative expense (2017 - $38 million gain; 2016 - $20 million loss; 2015 - $2 million loss) in the Consolidated Statements of Earnings.

4	Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

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1	Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.

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1	Financial and physical forward commodity contracts are valued using a market approach valuation technique.

2	Commodity options contracts are valued using an option model valuation technique.

3	One million British thermal units (mmbtu).

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1	Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

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1	The change in provincial and state income taxes from 2016 to 2017 reflects the increase in earnings from the Canadian operations and the impact of the United States tax reform on state income tax expense.

2	The amount was due to the enactment of the “Tax Cuts and Jobs Act” by the United States on December 22, 2017, which included a reduction in the federal corporate income tax rate from 35% to 21% effective for taxation years beginning after December 31, 2017.

3	The amount relates to the federal component of the tax effect a goodwill write-down pursuant to ASU 2017-04.

4	In November 2016 and September 2015, certain assets were sold to entities under common control. The intercompany gains realized on these transfers were eliminated. However, because these transactions involved the sale of partnership units, tax consequences have been recognized in earnings.

5	The amount in 2016 represents the federal component of the non-taxable portion of the gain on the sale of the South Prairie Region assets to unrelated party.

6	The decrease from 2015 to 2016 is due to the federal component of the tax effect of a valuation allowance on the deferred tax assets related to an outside basis temporary difference that, in 2015, was no longer more likely than not to be realized.

7	There was a change in assertion regarding the manner of recovery of the intercorporate investment in EIPLP such that deferred tax related to outside basis temporary differences was required to be recorded.

8	2015 included $17 million recovery related to the federal component of the tax effect of adjustments related to prior periods.

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1	The accumulated benefit obligation for our Canadian pension plans was $3.7 billion and $978 million as at December 31, 2017 and 2016, respectively. The accumulated benefit obligation for our United States pension plans was $$1.2 billion and $462 million as at December 31, 2017 and 2016, respectively.

2

Assets in the amount of $9 million (2016 - $8 million) and $40 million (2016 - $44 million), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in grantor trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes.

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1	Level 1 assets include assets with quoted prices in active markets for identical assets.

2	Level 2 assets include assets with significant observable inputs.

3	Level 3 assets include assets with significant unobservable inputs.

4	The fair values of the infrastructure and real estate investments are established through the use of valuation models.

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1

Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discount, debt issue costs and capital lease obligations. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above.

2	Excludes the debt issuance of US$800 million senior notes that occurred subsequent to December 31, 2017 (Note 30).

3	Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.

4	Includes capital and operating commitments.

5	Consists primarily of gas transportation and storage contracts (EGD), firm capacity payments and gas purchase commitments (Spectra Energy), transportation, service and product purchase obligations (MEP), and power commitments (EEP).

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1	The 2017 quarterly financial data reflects the effect of the Merger Transaction closed on February 27, 2017 (Note 7).

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•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets;

•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP; and

•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

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Item 5.02.	Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers; Compensatory Arrangements of Certain Officers

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