UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 6-K

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

Dated August 3, 2017

Commission file number 001-15254

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)

200, 425 – 1st Street S.W.

Calgary, Alberta, Canada  T2P 3L8

(Address of principal executive offices and postal code)

Indicate by check mark whether the Registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by regulation S-T Rule 101(b)(7):

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-216272, 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 333-185591) AND FORM F-10 (FILE NO. 333-213234) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

The following documents are being submitted herewith:

·                 Interim Report to Shareholders for the six months ended June 30, 2017

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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ENBRIDGE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS

June 30, 2017

GLOSSARY

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MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2017

This Management’s Discussion and Analysis (MD&A) dated August 3, 2017 should be read in conjunction with the unaudited interim consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) as at and for the three and six months ended June 30, 2017, prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). It should also be read in conjunction with the Company’s audited consolidated financial statements and MD&A for the year ended December 31, 2016 filed on February 17, 2017. For information relating to assets and operations acquired through the combination with Spectra Energy Corp (Spectra Energy), additional information is also available in Spectra Energy’s audited consolidated financial statements and MD&A for the year ended December 31, 2016 filed on SEDAR on February 24, 2017. All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com.

MERGER WITH SPECTRA ENERGY

On February 27, 2017, Enbridge announced the closing of the previously announced combination of Enbridge and Spectra Energy through a stock-for-stock merger transaction (the Merger Transaction).

Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge for each share of Spectra Energy common stock they held. Upon closing of the Merger Transaction, Enbridge shareholders owned approximately 57% of the combined company and Spectra Energy shareholders owned approximately 43%.

Spectra Energy, now wholly-owned by Enbridge, is one of North America’s leading natural gas delivery companies owning and operating a large, diversified and complementary portfolio of gas transmission, midstream gathering and processing and distribution assets. It also owns and operates a crude oil pipeline system that connects Canadian and United States producers to refineries in the United States Rocky Mountain and Midwest regions. The combination with Spectra Energy has created the largest energy infrastructure company in North America with an extensive portfolio of energy assets that are well positioned to serve key supply basins and end use markets and multiple business platforms through which to drive future growth. At the time of closing of the Merger Transaction, the Company’s capital program included $27 billion of commercially secured growth projects, which are expected to come into service through 2019, and an additional portfolio of projects in earlier stages of development expected to come into service by 2024. These growth projects, together with Enbridge’s existing businesses, are expected to generate dividend growth of 10% to 12% on average through 2024.

A more detailed description of each of the businesses and underlying assets acquired through the Merger Transaction is provided under Financial Results within this MD&A. The results of operations from assets acquired through the Merger Transaction are included in Enbridge’s financial statements and in this MD&A on a prospective basis from the closing date of the Merger Transaction.

Post-combination, the Company’s activities continue to be carried out through five business segments: Liquids Pipelines; Gas Pipelines and Processing; Gas Distribution; Green Power and Transmission; and Energy Services. Effective February 27, 2017, as a result of the Merger Transaction, and in addition to Enbridge assets previously held:

·         Liquids Pipelines also includes results from the operation of the Express-Platte System.

·         Gas Pipelines and Processing also includes Spectra Energy’s United States Storage and Transmission Assets, Canadian British Columbia Pipeline & Field Services, Canadian 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).

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

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A number of the assets acquired through the Merger Transaction and included in the business segments discussed above are owned through the Company’s investment in Spectra Energy Partners, LP (SEP). As a result of the combination, Enbridge now holds a 75% equity interest in SEP, a natural gas and crude oil infrastructure master limited partnership, which owns 100% of Texas Eastern Transmission, L.P. (Texas Eastern), 91% of Algonquin Gas Transmission, L.L.C. (Algonquin), 100% of East Tennessee Natural Gas, L.L.C. (East Tennessee), 100% of Express-Platte, 100% of Saltville Gas Storage Company L.L.C. (Saltville), 100% of Ozark Gas Gathering, L.L.C. and Ozark Gas Transmission, L.L.C., 100% of Big Sandy Pipeline, L.L.C., 100% of Market Hub Partners Holding, 100% of Bobcat Gas Storage, 78% of Maritimes & Northeast Pipeline, L.L.C. (M&N U.S.), 50% of Southeast Supply Header, L.L.C., 50% of Steckman Ridge, L.P. and 50% of Gulfstream Natural Gas System, L.L.C. (Gulfstream).

UNITED STATES SPONSORED VEHICLE STRATEGY

On April 28, 2017, Enbridge announced the completion of the strategic review of Enbridge Energy Partners, L.P. (EEP). The following actions, together with the measures announced in January 2017 and disclosed in the Company’s 2016 annual MD&A, were taken to enhance EEP’s value proposition to its unitholders and to Enbridge:

Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P.

On April 27, 2017, Enbridge completed its previously-announced merger through a wholly-owned subsidiary, through which it privatized Midcoast Energy Partners, L.P. (MEP) by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US$170 million.

On June 28, 2017, Enbridge, through a wholly-owned subsidiary, acquired all of EEP’s interest in the Midcoast gas gathering and processing business for cash consideration of US$1.3 billion plus existing indebtedness of MEP of US$953 million.

As a result of the above transactions, 100% of the Midcoast gas gathering and processing business is now owned by Enbridge.

Finalization of Bakken Pipeline System Joint Funding Agreement

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). 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. Under this arrangement, EEP has retained a five-year option to acquire an additional 20% interest. On finalization of this joint funding arrangement, EEP repaid the outstanding balance on its US$1.5 billion credit agreement with Enbridge, which it had drawn upon to fund the initial purchase.

EEP Strategic Restructuring Actions

On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by Enbridge at face value of US$1.2 billion through the issuance of 64.3 million Class A common units to Enbridge. Further, Enbridge irrevocably waived all of its rights associated with its 66.1 million Class D units and 1,000 Incentive Distribution Units (IDUs), in exchange for the issuance of 1,000 Class F units. The Class F units are entitled to (i) 13% of all distributions in excess of US$0.295 per EEP unit, but equal to or less than US$0.35 per EEP unit, and (ii) 23% of all distributions in excess of US$0.35 per EEP unit. The irrevocable waiver is effective with respect to distributions declared with a record date after April 27, 2017. In connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US$0.583 per unit to US$0.35 per unit.

The irrevocable waiver of the Class D units and IDUs, the redemption of the Series 1 Preferred Units and the reduction in the quarterly distributions will result in a lower contribution of earnings from EEP. This lower contribution will be partially offset by an increased contribution of earnings as a result of Enbridge’s increased ownership in the Class A common units post restructuring.

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ASSET MONETIZATION

In conjunction with the announcement of the Merger Transaction in September 2016, the Company announced its intention to divest $2 billion of assets over the ensuing 12 months in order to further strengthen its post-combination balance sheet and enhance the financial flexibility of the combined entity. With the completion of the secondary offering noted below, the Ozark pipeline system sale, the Olympic refined products pipeline sale and other divestitures completed in 2016, the Company has exceeded the $2 billion monetization target.

On April 18, 2017, the Company and Enbridge Income Fund Holdings Inc. (ENF) completed the secondary offering of 17,347,750 ENF common shares to the public at a price of $33.15 per share, for gross proceeds to Enbridge of approximately $0.6 billion (the Secondary Offering). To effect the Secondary Offering, Enbridge exchanged 21,657,617 Enbridge Income Fund (Fund) units it owned for an equivalent amount of ENF common shares. In order to maintain its 19.9% ownership interest in ENF, Enbridge retained 4,309,867 of the common shares it received in the exchange, and sold the balance under the Secondary Offering. Enbridge used the proceeds from the Secondary Offering to pay down short-term debt, pending reinvestment by the Company in its growing portfolio of secured projects. Upon closing of the Secondary Offering, the Company’s total economic interest in ENF decreased from 86.9% to 84.6%.

CONSOLIDATED EARNINGS

EARNINGS BEFORE INTEREST AND INCOME TAXES

For the three and six months ended June 30, 2017, earnings before interest and income taxes (EBIT) were $2,099 million and $3,728 million, respectively, compared with $731 million and $2,907 million for the three and six months ended June 30, 2016. Earnings for the three and six months ended June 30, 2017 were positively impacted by contributions from new assets following the completion of the Merger Transaction on February 27, 2017.

The positive impact to EBIT resulting from the Merger Transaction’s new assets was partially offset by lower results in Energy Services and the Liquids Pipelines segment as discussed below.

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The comparability of the Company’s earnings period-over-period is also impacted by a number of unusual, non-recurring or non-operating factors that are enumerated in the Non-GAAP Reconciliation tables, the most significant of which are changes in unrealized derivative fair value gains and losses. For the three months ended June 30, 2017, the Company’s EBIT reflected $461 million of unrealized derivative fair value gains, compared with losses of $98 million in the corresponding 2016 period. For the six months ended June 30, 2017, the Company’s EBIT reflected $877 million of unrealized derivative fair value gains, compared with gains of $834 million in the corresponding 2016 period. The Company has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks which creates volatility in short-term earnings. Over the long term, Enbridge believes its hedging program supports the reliable cash flows and dividend growth upon which the Company’s investor value proposition is based.

In addition, the comparability of period-over-period EBIT was impacted by the recognition of an impairment of $176 million ($103 million after-tax attributable to Enbridge) in the second quarter of 2016 related to Enbridge’s 75% joint venture interest in Eddystone Rail Company, LLC (Eddystone Rail), a rail-to-barge transloading facility located in Greater Philadelphia, Pennsylvania.

EBIT for the six months ended June 30, 2017 also reflected charges of $178 million ($130 million after-tax) with respect to costs incurred in conjunction with the Merger Transaction, as well as $208 million ($146 million after-tax) of employee severance costs in relation to the Company’s enterprise-wide reduction of workforce in March 2017 and restructuring costs in connection with the completion of the Merger Transaction.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Earnings attributable to common shareholders for the three months ended June 30, 2017 were $919 million, or $0.56 per common share, compared with $301 million, or $0.33 per common share, for the three months ended June 30, 2016. Earnings attributable to common shareholders for the six months ended June 30, 2017 were $1,557 million, or $1.11 per common share, compared with $1,514 million, or $1.69 per common share, for the six months ended June 30, 2016.

In addition to the factors discussed in Earnings Before Interest and Income Taxes above, interest expense for the three and six months ended June 30, 2017 was higher, compared with the corresponding 2016 periods, as a result of debt assumed in the Merger Transaction. Preference share dividends were also higher reflecting additional preference shares issued in the fourth quarter of 2016 to partially fund the Company’s growth capital program.

Income tax expense increased for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods, largely due to the increase in earnings.

Earnings attributable to noncontrolling interests and redeemable noncontrolling interests increased in the second quarter and the first half of 2017, compared with the corresponding 2016 periods. The increase was driven by additional noncontrolling interests associated with the assets acquired in the Merger Transaction and lower earnings attributable to noncontrolling interests in EEP during 2016.

Lower earnings per common share for the six months ended June 30, 2017, compared with the corresponding 2016 period, reflected the issuance of approximately 691 million common shares in February 2017 as part of the consideration for the Merger Transaction, the issuance of approximately 75 million common shares in 2016 through a 56 million follow-on common share offering in the first quarter of 2016, and ongoing issuances under the Company’s Dividend Reinvestment Program.

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FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A to provide information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “expect”, “project”, “estimate”, “forecast”, “plan”, “intend”, “target”, “believe”, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected EBIT or expected adjusted EBIT; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected performance of the Liquids Pipelines business; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for the Company’s commercially secured growth program; expected future growth and expansion opportunities; expectations about the Company’s joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions; estimated future dividends; recovery of the costs of the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program); expected expansion of the T-South System; expected capacity of the Hohe See Expansion Offshore Wind Project; expected costs in connection with Line 6A and Line 6B crude oil releases; expected effect of Aux Sable Consent Decree; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the Merger Transaction including the combined Company’s scale, financial flexibility, growth program, future business prospects and performance; impact of the Canadian L3R Program on existing integrity programs; dividend payout policy; dividend growth and dividend payout expectation; and expectations on impact of hedging program.

Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labour and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; weather; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of the dividend policy on the Company’s future cash flows; credit ratings; capital project funding; expected EBIT or expected adjusted EBIT; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates and may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to the impact of the Merger Transaction on the Company, expected EBIT, adjusted EBIT, earnings/(loss), adjusted earnings/(loss) and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes.

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

NON-GAAP MEASURES

This MD&A contains references to adjusted EBIT, adjusted earnings and adjusted earnings per common share. Adjusted EBIT represents EBIT adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors included in adjusted EBIT, as well as adjustments for unusual, non-recurring or non-operating factors in respect of interest expense, income taxes, noncontrolling interests and redeemable noncontrolling interests on a consolidated basis. These factors, referred to as adjusting items, are reconciled and discussed in the financial results sections for the affected business segments.

Management believes the presentation of adjusted EBIT, adjusted earnings and adjusted earnings per share gives useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company. Management uses adjusted EBIT and adjusted earnings to set targets and to assess the performance of the Company. Adjusted EBIT, adjusted EBIT for each segment, adjusted earnings and adjusted earnings per common share are not measures that have standardized meaning prescribed by U.S. GAAP and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers.

The tables below provide a reconciliation of the GAAP and non-GAAP measures.

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NON-GAAP RECONCILIATION – EBIT TO ADJUSTED EARNINGS

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NON-GAAP RECONCILIATION – ADJUSTED EBIT TO ADJUSTED EARNINGS

Adjusted EBIT

For the three and six months ended June 30, 2017, adjusted EBIT was $1,713 million and $3,228 million, respectively, an increase of $624 million and $765 million over the corresponding three and six-month periods in 2016. The largest driver of adjusted EBIT growth over the prior year periods was the contributions of new assets acquired in the Merger Transaction which closed on February 27, 2017. Also contributing to the period-over-period growth in adjusted EBIT were increased contributions from the Green Power and Transmission segment. These positive contributions were partially offset by warmer weather in the franchise areas served by the Company’s gas distribution utilities and lower results in the Energy Services and Liquids Pipelines segments.

Growth in adjusted EBIT was most pronounced in the Gas Pipelines and Processing segment, where a majority of the new assets acquired through the Merger Transaction are reported. Growth for this segment also reflected contributions from the Tupper Main and Tupper West gas plants (the Tupper Plants) acquired in April 2016.

Excluding contributions from Express-Platte as part of the Merger Transaction, Liquids Pipelines adjusted EBIT decreased in the three and six months ended June 30, 2017, compared with the corresponding 2016 periods. The second quarter of 2017 was impacted by several transitory items including a significant unexpected outage and accelerated maintenance at a customer’s upstream facility, additional related and unrelated production disruptions, and a hydrostatic testing program on Line 5 during the month of June 2017. The combined impact on the mainline system of these factors was approximately $50 million in the second quarter of 2017. Up until the month of June, the mainline system had been delivering near record volumes and operating under apportionment in heavy crude oil service. Apportionment on the mainline system also impacted the adjusted EBIT contribution of certain downstream pipelines during the first and second quarters of 2017. Liquids Pipelines reported performance was further impacted by a change in practice whereby the Company no longer includes cash received under certain take-or-pay contracts with make-up rights in its determination of adjusted EBIT. In addition, the divestiture of certain assets and lower surcharge revenues decreased adjusted EBIT. Adjusted EBIT generated by Liquids Pipelines is expected to grow over the second half of 2017 as throughput on the mainline system is expected to return to record levels achieved earlier in the year and capacity optimization projects, undertaken in the first half of the year to alleviate apportionment on the mainline system, are operationalized.

Within the Gas Distribution segment, Enbridge Gas Distribution Inc. (EGD) generated lower adjusted EBIT for the six months ended June 30, 2017, compared with the corresponding 2016 period, primarily due to lower distribution revenues attributable to warmer than normal weather in the first half of 2017. Effective January 1, 2017, EGD ceased to exclude the effect of warmer/colder weather from its adjusted EBIT. In the first half of 2017 warmer than normal weather impacted EGD’s adjusted EBIT by approximately $23 million. The period-over-period decrease in EGD’s adjusted EBIT was more than offset by contributions from Union Gas since the completion of the Merger Transaction.

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Energy Services adjusted EBIT for the three and six months ended June 30, 2017 reflected compressed location and quality differentials in certain markets, lower refinery demand for certain products and fewer opportunities to achieve profitable margins on facilities where the Company holds capacity obligations. Adjusted EBIT from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

The increase in adjusted loss before interest and income taxes reported within Eliminations and Other reflects higher unallocated corporate costs which primarily resulted from the Merger Transaction, partially offset by synergies achieved thus far on integration of corporate functions.

Adjusted Earnings

Adjusted earnings were $662 million, or $0.41 per common share, for the three months ended June 30, 2017, compared with $456 million, or $0.50 per common share, for the three months ended June 30, 2016. Adjusted earnings were $1,337 million, or $0.95 per common share, for the six months ended June 30, 2017, compared with $1,119 million, or $1.25 per common share, for the six months ended June 30, 2016.

In addition to the factors discussed in Adjusted EBIT above, the comparability of adjusted earnings is consistent with the discussion in Earnings Attributable to Common Shareholders above.

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GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

The following table summarizes the status of the Company’s commercially secured projects, organized by business segment. Expenditures to date reflect total cumulative expenditures incurred from inception of the project to June 30, 2017.

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The description of each of the Enbridge projects, including those being undertaken by EEP and the Fund Group, which is comprised of the Fund, Enbridge Commercial Trust, Enbridge Income Partners LP (EIPLP) and the subsidiaries and investees of EIPLP, is provided in the Company’s 2016 annual MD&A. Projects where significant developments have occurred since February 17, 2017, the date of the filing of the Company’s MD&A for the year ended December 31, 2016, including the commercially secured growth projects acquired upon close of the Merger Transaction, are discussed below.

LIQUIDS PIPELINES

Norlite Pipeline System (the Fund Group)

Norlite Pipeline System, a new industry diluent pipeline originating from the Company’s Stonefell Terminal, was placed into commercial service on May 1, 2017. To meet the needs of multiple producers in the Athabasca oil sands region, the 24-inch diameter pipeline provides an initial capacity of approximately 218,000 Barrels per day (bpd) of diluent, with the potential to be further expanded to approximately 465,000 bpd of capacity with the addition of pump stations. Keyera Corp. has elected to participate in the Norlite Pipeline System as a 30% non-operating owner.

Bakken Pipeline System (EEP)

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). The Bakken Pipeline System was placed into service on June 1, 2017. It connects the Bakken formation in North Dakota to markets in the eastern Petroleum Administration for Defense Districts and the United States Gulf Coast, providing customers with access to premium markets at a competitive cost.

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.

Lakehead System Mainline Expansion (EEP)

The Lakehead System Mainline Expansion includes several projects to expand capacity of the Lakehead Pipeline System (Lakehead System) mainline between its origin at the United States/Canada border, near Neche, North Dakota, and Flanagan, Illinois. These projects include the expansion of Alberta Clipper (Line 67) and Southern Access (Line 61) and the construction of the Spearhead North Twin pipeline (Line 78). The expansion of Line 67 and construction of Line 78 were completed in 2015.

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The Line 67 pipeline capacity expansion remains subject to the receipt of an amendment to the current Presidential Permit to allow for operation of the Line 67 pipeline at the United States/Canada border at its currently planned operating capacity of 800,000 bpd. On February 10, 2017, the United States Department of State (DOS), the agency that is responsible for issuing permits for cross-border pipelines pursuant to a delegation of authority by the President under an Executive Order, issued a draft Supplemental Environmental Impact Statement (SEIS), which determined that there were no significant adverse environmental impacts from the planned capacity increase. The public comment period on the draft SEIS closed on March 27, 2017. The DOS is reviewing all received comments and preparing a final SEIS. As required by the Executive Order, the DOS initiated a 90-day inter-agency consultation period to solicit comments from certain other federal agencies on whether the Line 67 expansion will serve the national interest. The inter-agency consultation period commenced on March 28, 2017. Following the issuance of the final SEIS and completion of the inter-agency consultation process, the Administration will make a decision and issue a Presidential Permit if it finds that doing so is in the national interest. The Administration’s decision is expected later in the year.

The remaining scope of the Lakehead System Mainline Expansion included the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois. The expansion to increase the pipeline capacity to 1,200,000 bpd at an expected cost of approximately US$0.4 billion was substantially completed in June of 2017. In conjunction with shippers, a decision was made to delay the in-service date of this phase of the Southern Access expansion to 2019 to align more closely with the anticipated in-service date for the United States portion of the Line 3 Replacement Program (U.S. L3R Program).

EEP will operate this project on a cost-of-service basis. The Lakehead System Mainline Expansion is funded 75% by Enbridge and 25% by EEP under a joint funding agreement. Under that agreement, EEP has the option to increase its economic interest held by up to an additional 15% at cost.

Line 3 Replacement Program

The Line 3 Replacement Program (L3R Program) will support the safety and operational reliability of the mainline system, enhance system flexibility, allow the Company and EEP to optimize throughput on the mainline system and restore approximately 370,000 bpd of capacity from western Canada into Superior, Wisconsin.

Canadian Line 3 Replacement Program (the Fund Group)

The Canadian L3R Program will complement existing integrity programs by replacing approximately 1,084 kilometres (673 miles) of the remaining line segments of the existing Line 3 pipeline between Hardisty, Alberta and Gretna, Manitoba.

In April 2016, the National Energy Board (NEB) found that the Canadian L3R Program is in the Canadian public interest and issued final conditions and a recommendation to the Federal Cabinet to approve the issuance of the Certificate of Public Convenience and Necessity (the Certificate) for the construction and operation of the pipeline and related facilities. Approval was received from the Government of Canada on November 29, 2016, with no material changes to permit conditions and on December 1, 2016, the NEB issued the Certificate. Once the Certificate was issued, Natural Resources Canada (NRCan) released the final assessment of the upstream greenhouse gas (GHG) emissions, as well as reports summarizing the additional Crown Consultation with Indigenous groups and the public online survey conducted by NRCan.

In December 2016, the Manitoba Metis Federation (MMF) and the Association of Manitoba Chiefs (AMC) applied to the Federal Court of Appeal (FCA) for leave, which was subsequently granted, to judicially review the Government of Canada’s decision to approve the Canadian L3R Program. On July 4, 2017, the MMF discontinued its judicial review application. It is expected that the FCA’s hearing of the AMC judicial review application will take place during 2018, although a hearing date has not yet been set. The potential outcome of this matter cannot be predicted at this time.

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On July 7, 2017, the NEB approved the Plan, Profile and Book of Reference for the Canadian L3R Program, meaning that the detailed route for the Canadian L3R Program has been approved. All required pre-construction filings have been submitted to the NEB. Enbridge is awaiting the approval of the two remaining conditions by the NEB before construction can proceed.

Based on the updated execution plan, the revised cost of the project is $5.3 billion in Canada. This modest increase is roughly 8% above prior estimates and reflects the ongoing delays in the regulatory process, as well as some additional scope, route modifications and other changes as a result of the extensive consultation efforts and obligation to meet permit conditions. The impact of these additional costs are fully offset by lower estimated operating costs and a stronger United States dollar relative to the original project assumptions.

United States Line 3 Replacement Program (EEP)

The U.S. L3R Program will complement existing integrity programs by replacing approximately 576 kilometres (358 miles) of the remaining line segments of the existing Line 3 pipeline between Neche, North Dakota and Superior, Wisconsin. EEP has the authorization to replace Line 3 in North Dakota and Wisconsin.

EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate of Need and an approval of the pipeline’s route (Route Permit) from the Minnesota Public Utilities Commission (MNPUC). The MNPUC found both the Certificate of Need and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. On February 1, 2016, the MNPUC issued a written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental Impact Statement (EIS) before Certificate of Need and Route Permit processes commence. The DOC’s draft EIS was issued on May 15, 2017 and public comments regarding the draft EIS were accepted by the DOC until July 10, 2017. The DOC has stated that it anticipates issuing the final EIS in August 2017. Construction of the Wisconsin portion of U.S. L3R Program commenced in late June 2017.

Based on the updated execution plan, the revised cost of the project is US$2.9 billion in the United States. This modest increase is roughly 12% above prior estimates and reflects the ongoing delays in the regulatory process, as well as some additional scope, route modifications and other changes as a result of the extensive consultation efforts and obligation to meet permit conditions. EEP will recover the costs plus a return on capital based on its existing Facilities Surcharge Mechanism with the initial term of the agreement being 15 years. For the purpose of the toll surcharge, the agreement specifies a 30-year recovery of the capital based on a cost-of-service methodology.

On January 26, 2017, Enbridge and EEP entered into an agreement for the joint funding of the U.S. L3R Program, whereby Enbridge and EEP will fund 99% and 1%, respectively, of the project cost. Enbridge has reimbursed EEP approximately US$450 million for expenditures incurred to date on the project and it will fund 99% of the capital costs through construction. EEP has the option to increase its economic interest by up to 40% at Enbridge’s cost until four years after the project is placed into service.

GAS PIPELINES AND PROCESSING

Sabal Trail (SEP)

The Sabal Trail project, a joint venture with NextEra Energy and Duke Energy, was placed into service in early July 2017. The project will provide firm natural gas transportation to Florida Power & Light Company for its power generation needs and to Duke Energy Florida for its proposed natural gas plant in Florida. Facilities include a new 748 kilometre (465 mile) pipeline, laterals and various compressor stations. This new pipeline infrastructure is located in Alabama, Georgia and Florida, and will add approximately 1,100 million cubic feet per day (mmcf/d) of new capacity to access onshore shale gas supplies once approved future expansions are completed.

Access South, Adair Southwest and Lebanon Extension (SEP)

SEP’s Access South, Adair Southwest and Lebanon Extension projects will provide shippers with the opportunity to deliver new natural gas supplies from the Appalachian region of the United States to markets in the Midwest and Southeast regions of the United States where demand for natural gas is high. The facilities for these projects include pipeline looping, as well as modifications and expansions of existing compressor stations on SEP’s Texas Eastern pipeline system. The combined projects are designed to deliver 622 mmcf/d of gas to customers in Ohio, Kentucky and Mississippi. These projects are expected to be placed into service in the second half of 2017.

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Atlantic Bridge (SEP)

The Atlantic Bridge project is an expansion designed to provide additional capacity of 133 mmcf/d to SEP’s Algonquin Gas Transmission and Maritimes & Northeast pipeline systems into New England and to specific end use markets in the Canadian Maritime provinces. The expansion primarily consists of the replacement of 10 kilometres (6 miles) of 26-inch pipeline with 42-inch pipeline, compression additions in Connecticut and a new compressor station in Massachusetts. The Connecticut portion of the project is expected to be placed into service in the fourth quarter of 2017. The Massachusetts portion of the project is expected to be placed into service in late 2018.

NEXUS (SEP)

Under a 50% joint venture with DTE Energy Company, SEP has begun pre-construction work on the NEXUS project, which is a new pipeline system designed to transport up to 1.5 billion cubic feet per day (bcf/d) from SEP’s Texas Eastern pipeline system in Ohio to the Union Gas Dawn hub in Ontario. The facilities will consist of approximately 410 kilometres (255 miles) of 36-inch pipeline across northern Ohio to the Detroit, Michigan area, addition of four new compressor stations totalling 130,000 horsepower and six meter stations. Approval of the NEXUS project remains pending before the Federal Energy Regulatory Commission (FERC) due to a lack of quorum. While the NEXUS certificate application remains pending, the record supporting the Final EIS and Applications are complete and ready for prompt FERC approval once a quorum is restored. Once the expected approval is received, a revised 2018 in-service date will be identified.

High Pine

Westcoast’s High Pine project on the British Columbia Pipeline includes a 240 mmcf/d expansion of the T-North pipeline system consisting of two 42-inch pipeline loops totalling approximately 37 kilometres (23 miles) in length in the Fort St. John region of British Columbia. The expansion consists of an additional compressor unit with associated infrastructure at the Sunset Creek compressor site in northeastern British Columbia. The project is expected to be placed into service by the end of 2017.

Reliability and Maintainability Project

Westcoast’s Reliability and Maintainability (RAM) project was designed to enhance the performance of the southern segment of the British Columbia Pipeline system to accommodate the increased base load on the system, which is driven by a combination of increased gas production in the northeastern region of British Columbia and demand driven by end users, such as incremental industrial projects, electric power generation and small-scale liquefied natural gas (LNG). The RAM project involves upgrading the southern segment of the British Columbia Pipeline system with three compressor station replacements. It will prepare the British Columbia Pipeline system to operate at a higher load factor as higher utilization rates are expected from new incremental year-round loads. The first two compressor stations are expected to be placed into service in the fourth quarter of 2017, with the final station expected to be placed into service in the first half of 2018.

Valley Crossing Pipeline

The Valley Crossing Pipeline project will provide new market opportunities for Texas gas producers and help Mexico meet its growing electric generation needs as generators shift away from fuel oil and imported LNG. The project will include a new 269 kilometre (167 mile) mainline pipeline that will consist of approximately 221 kilometres (138 miles) of 48-inch pipe and 48 kilometres (30 miles) of 42-inch pipe. The pipeline is designed to carry 2.6 bcf/d of gas from 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 Valley Crossing Pipeline is expected to be placed into service in the second half of 2018.

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Spruce Ridge Program

Under the Spruce Ridge Program, Westcoast is pursuing an expansion of the British Columbia Pipeline in northern British Columbia. The expansion service agreements were executed in late 2016 and the final scoping of the project is underway, with a targeted in-service date in 2019.

British Columbia Pipeline T-South System

In the second quarter of 2017, Enbridge completed a successful binding open season on its British Columbia Pipeline T-South system for delivery of an incremental 190 mmcf/d of natural gas into the Huntington/Sumas market at the United States/Canada border. All customer contracts associated with the open season have been executed. The T-South system is currently fully contracted and an expansion is necessary to meet increasing customer demand as a result of rapidly growing production in the Montney region. The project will include looping of the T-South system and upgrades at compressor stations along the pipeline system at a cost of approximately $1 billion and is expected to be in-service by late 2020.

GAS DISTRIBUTION

2017 Dawn-Parkway Expansion

The Union Gas 2017 Dawn-Parkway expansion project in Ontario involves a 419 mmcf/d expansion of the Dawn to Parkway transmission system consisting of the addition of a new 44,500 horsepower compressor at each of the Dawn, Lobo and Bright compressor stations in Ontario. The Dawn-Parkway expansion project is expected to be placed into service in the fourth quarter of 2017.

GREEN POWER AND TRANSMISSION

Hohe See Expansion Project

In June 2017, the Company announced it had moved forward on its option to partner with German utility EnBW on an expansion of the previously announced Hohe See Offshore Wind Project (Hohe See Project). The Hohe See expansion project, to be located in the vicinity of the 497 megawatt Hohe See Project, will have a capacity of 112 megawatts. Similar to the Hohe See Project, the Hohe See expansion project will be constructed under fixed-price engineering, procurement, construction and installation contracts which have been secured with key suppliers. The Hohe See expansion project is backed by a government legislated 20-year revenue support mechanism and is expected to be placed into service alongside the Hohe See Project in 2019.

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

The following projects have been announced by the Company, but have not yet met the Company’s criteria to be classified as commercially secured. The Company also has a large portfolio of additional projects under development that have not yet progressed to the point of public announcement.

GAS PIPELINES AND PROCESSING

Gulf Coast Express Pipeline Project

In April 2017, DCP Midstream announced the signing of a letter of intent with Kinder Morgan Texas Pipeline LLC to participate in the development of the proposed Gulf Coast Express Pipeline Project. The project will provide an outlet for increased natural gas production from the Permian Basin to growing markets along the Texas Gulf Coast. The project is designed to transport up to 1.7 bcf/d of natural gas through approximately 692 kilometres (430 miles) of 42-inch pipeline from the Waha, Texas area to Agua Dulce, Texas. The project is expected to be placed into service during the second half of 2019, subject to obtaining sufficient shipper commitments.

GREEN POWER AND TRANSMISSION

Éolien Maritime France SAS

Enbridge has a 50% interest in Éolien Maritime France SAS (EMF), a French offshore wind development company. EMF is co-owned by Enbridge and EDF Energies Nouvelles, a subsidiary of Électricité de France S.A. EMF, through subsidiary companies, which holds licenses for three large-scale offshore wind farms off the coast of France. Combined, the three projects will have a capacity of 1,428 megawatts of power. The development of these projects is subject to a final investment decision and regulatory approvals, the timing of which is not yet certain. Enbridge’s portion of the costs incurred to date is approximately $226 million (€148 million).

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FINANCIAL RESULTS

For assets owned by Enbridge as at December 31, 2016, a description of the asset and associated risks can be found under the relevant segment discussion in the Company’s MD&A for the year ended December 31, 2016. For assets acquired through the Merger Transaction, the description of the asset and any additional risks specifically associated with these assets have been included with the discussion of the operating results of individual assets that follows. The performance summaries below reflect the financial results of the assets acquired in the Merger Transaction from the closing date of the merger.

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LIQUIDS PIPELINES

Earnings Before Interest and Income Taxes

1         Includes adjusted EBIT from Express-Platte System since the completion of the Merger Transaction on February 27, 2017. For additional information, refer to Merger with Spectra Energy.

2         Effective January 1, 2017, the Company no longer makes such an adjustment to its EBIT.

Additional details on items impacting Liquids Pipelines EBIT include:

·                  Canadian Mainline EBIT for each period reflects changes in unrealized fair value gains and losses on derivative financial instruments used to manage foreign exchange and commodity price risk inherent within the Competitive Toll Settlement (CTS).

·                  Southern Lights Pipeline EBIT for each period reflects changes in unrealized fair value gains and losses on derivative financial instruments used to manage foreign exchange risk on United States dollar cash flows from the Southern Lights Class A units.

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·                  Bakken System EBIT for 2017 includes the gain on sale of pipe offset by project wind-down costs related to EEP’s Sandpiper Project.

·                  Feeder Pipelines and Other loss before interest and income taxes for 2016 included impairment charges related to Enbridge’s 75% joint venture interest in Eddystone Rail attributable to market conditions that impacted volumes at the rail facility.

Canadian Mainline

Canadian Mainline adjusted EBIT increased in the second quarter of 2017, compared with the corresponding 2016 period, primarily due to a higher Canadian Mainline International Joint Tariff (IJT) Residual Benchmark Toll and higher average throughput. The Canadian Mainline also benefitted from a higher foreign exchange hedge rate used to record Canadian Mainline revenues. For the second quarter of 2017, the effective hedged rate for the translation of Canadian Mainline United States dollar transactional revenues was $1.04, compared with $1.03 for the corresponding 2016 period.

Throughput on the mainline system was affected by unusual events in the second quarter of both 2016 and 2017. In 2016, wildfires in Alberta resulted in a curtailment of production from oil sands facilities and the temporary shutdown of certain of the Company’s upstream pipelines and terminal facilities, decreasing second quarter 2016 adjusted EBIT by approximately $30 million. While higher than the second quarter of 2016, throughput in the second quarter of 2017 was affected by a significant unexpected outage and accelerated maintenance at a customer’s upstream facility, and additional related and unrelated production disruptions.

The outages experienced in June were temporary and adjusted EBIT on the Canadian Mainline is expected to be positively impacted in the second half of 2017 as throughput returns to levels experienced earlier in the year and apportionment on the system is relieved through capacity optimizations that were implemented in the first half of the year.

Canadian Mainline adjusted EBIT decreased in the first half of 2017, compared with the corresponding 2016 period. Higher adjusted EBIT in the second quarter of 2017, as discussed above, was offset by the lower first quarter results. First quarter results in 2017 decreased, compared with the corresponding 2016 period, due to the absence of hydrostatic test surcharge revenue recognized in 2017, a lower average Canadian Mainline IJT Residual Benchmark Toll and a lower foreign exchange hedge rate used to record United States dollar denominated Canadian Mainline revenues. For the first quarter of 2017, the effective hedged rate for the translation of Canadian Mainline United States dollar transactional revenues was $1.04, compared with $1.11 for the corresponding 2016 period.

Supplemental information related to the Canadian Mainline for the three and six months ended June 30, 2017 and 2016, is provided below:

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Throughput Volume

Lakehead System

Lakehead System adjusted EBIT decreased in the second quarter of 2017, compared with the corresponding 2016 period. The second quarter decrease was primarily due to a lower Lakehead System Local Toll, and increased property taxes and depreciation expense resulting from an increased asset base and hydrostatic testing costs in the second quarter of 2017. These negative impacts were partially offset by a higher average United States to Canadian dollar exchange rate (Average Exchange Rate) in the second quarter of 2017, compared with the corresponding 2016 period, and higher average throughput reflecting system optimization.

In addition, the higher average throughput in the second quarter of 2017 compared to 2016 was partially driven by the negative impact of the northeastern Alberta wildfires experienced in 2016. The wildfires resulted in a curtailment of production from oil sands facilities and the temporary shutdown of certain of the Company’s upstream pipelines and terminal facilities, decreasing adjusted EBIT by approximately $38 million for the three months ended June 30, 2016. While higher than the second quarter of 2016, throughput in the second quarter of 2017 was affected by a significant unexpected outage and accelerated maintenance at a customer’s upstream facility, additional related and unrelated production disruptions, and a hydrostatic testing program on Line 5 during the month of June 2017.

The outages experienced in June were temporary and adjusted EBIT on the Lakehead System is expected to be positively impacted in the second half of 2017 as throughput returns to levels experienced earlier in the year and apportionment on the system is relieved through capacity optimizations that were implemented in the first half of the year.

Lakehead System adjusted EBIT decreased in the first half of 2017, compared with the corresponding 2016 period. The decrease in the second quarter of 2017, as discussed above, was partially offset by higher first quarter results in 2017. Strong operating performance in the first quarter of 2017 was driven by higher long-haul throughput and a higher Lakehead System Local Toll compared to 2016. As discussed under Canadian Mainline above, higher throughput on the Lakehead System in the first quarter of 2017 reflected system optimization. It is expected that volumes will increase for the remainder of 2017 as a result of continued optimization efforts.

Excluding the impact of foreign exchange translation to Canadian dollars, Lakehead System adjusted EBIT was US$222 million and US$516 million for the three and six months ended June 30, 2017, respectively, compared with US$279 million and US$535 million for corresponding 2016 periods.

As noted above, partially offsetting the three and six months ended June 30, 2017 decrease in Lakehead System adjusted EBIT was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period. A portion of Lakehead System United States dollar EBIT is hedged as part of the Company’s enterprise-wide financial risk management program. The Company uses foreign exchange derivative instruments to manage the foreign exchange risk arising from its United States businesses including the Lakehead System. Realized gains and losses from these derivative instruments are reported within Eliminations and Other. For further details refer to Eliminations and Other.

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Throughput Volume

1   Throughput volume represents mainline system deliveries to the United States midwest and eastern Canada.

Average Exchange Rate

Mid-Continent and Gulf Coast

Mid-Continent and Gulf Coast adjusted EBIT decreased for the three and six months ended June 30, 2017, compared with the corresponding 2016 period, primarily due to lower contributions from Flanagan South Pipeline (Flanagan South) and the absence of adjusted EBIT from the Ozark Pipeline that was sold in the first quarter of 2017. The decrease in adjusted EBIT was partially offset by a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period.

Adjusted EBIT reported by Flanagan South in the first half of 2017 was impacted by apportionments on the mainline system and by a change in treatment of deferred revenue created by take-or-pay contracts with make-up rights in the determination of adjusted EBIT. When committed shippers on Flanagan South are unable to fulfill their volume commitments due to apportionment, they are provided with temporary relief to make up those volumes during the course of their contracts or the apportioned volumes are added on to the end of the contract term. Due to upstream mainline apportionment, committed shippers on Flanagan South were provided higher apportionment relief in the first half of 2017, compared with the first half of 2016, which resulted in lower contractual cash payments from these shippers. For the purposes of adjusted EBIT, prior to January 1, 2017, the Company reflected contributions from these contracts rateably over the life of the contract, consistent with contractual cash payments under the contract. Effective January 1, 2017, for the purposes of determining adjusted EBIT, the Company discontinued this treatment.

Excluding the impact of foreign exchange translation to Canadian dollars, Mid-Continent and Gulf Coast adjusted EBIT was US$95 million and US$185 million for the three and six months ended June 30, 2017, respectively, compared with US$125 million and US$257 million for the three and six months ended June 30, 2016.

As noted above, partially offsetting the three and six months ended June 30, 2017 decrease in adjusted EBIT was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period. Similar to Lakehead System, a portion of Mid-Continent and Gulf Coast United States dollar EBIT is hedged as part of the Company’s enterprise-wide financial risk management program, and realized gains and losses from the derivative instruments used to hedge foreign exchange risk arising from the Company’s investment in United States businesses are reported within Eliminations and Other. For further details refer to Eliminations and Other.

Express-Platte System

The Express-Platte pipeline system, an approximate 2,736 kilometre (1,700 mile) crude oil transportation system, which begins in Hardisty, Alberta, and terminates in Wood River, Illinois, is comprised of both the Express and Platte crude oil pipelines and crude oil storage of approximately 5.6 million barrels. The Express pipeline carries crude oil to United States refining markets in the Rockies area, including Montana, Wyoming, Colorado and Utah. The Platte pipeline, which interconnects with the Express pipeline in Casper, Wyoming, transports crude oil predominantly from the Bakken shale and western Canada to refineries in the Midwest. The Company has a 75% indirect ownership interest in Express-Platte, through its investment in SEP.

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Express capacity is typically committed under long-term take-or-pay contracts with shippers. A small portion of Express capacity and all of the Platte capacity is used by uncommitted shippers who pay only for the pipeline capacity they actually use in a given month.

Express-Platte is exposed to the same business risks as the Company’s other Liquids Pipelines assets as discussed in Enbridge’s MD&A for the year ended December 31, 2016.

Results of Operations

Express-Platte adjusted EBIT for the three and six months ended June 30, 2017, reflects results of operations since the completion of the Merger Transaction on February 27, 2017.

When compared to pre-Merger results from the prior year, Express-Platte results include higher crude oil transportation revenues due to higher uncommitted volumes on the Express pipeline, higher tariff rates on the Express pipeline due to annual escalations, and higher volumes from the Express Enhancement expansion project placed into service in October 2016. These higher revenues were partially offset by higher power costs due to higher throughput.

Bakken System

Bakken System adjusted EBIT decreased for the three months ended June 30, 2017, compared with the corresponding 2016 period. The decrease in adjusted EBIT reflected lower rates and lower rail revenues on the United States portion of the Bakken System owned by EEP, partially offset by the positive impact of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period.

Bakken System adjusted EBIT decreased for the six months ended June 30, 2017, compared with the corresponding 2016 period, primarily due the three month reasons discussed above.

Excluding the impact of foreign exchange translation to Canadian dollars, Bakken System adjusted EBIT was US$31 million and US$51 million for the three and six months ended June 30, 2017, respectively, compared with US$36 million and US$73 million for the corresponding 2016 periods. The decrease in adjusted EBIT for the three and six months ended June 30, 2017, for the United States portion of the Bakken System was attributable to lower surcharge revenues as certain surcharge rates expired effective December 31, 2016.

As noted above, partially offsetting the three and six months ended June 30, 2017 decrease in adjusted EBIT was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in the second quarter of 2017, compared with the corresponding 2016 period. Similar to Lakehead System, a part of the United States portion of the Bakken System United States dollar EBIT is hedged under the Company’s enterprise-wide financial risk management program, and realized gains and losses from the derivative instruments used to hedge foreign exchange risk arising from the Company’s investment in United States businesses are reported within Eliminations and Other. For further details refer to Eliminations and Other.

Feeder Pipelines and Other

Feeder Pipelines and Other adjusted EBIT decreased for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods, reflecting the absence of EBIT from the South Prairie Region assets that were sold in December 2016.

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GAS PIPELINES AND PROCESSING

Earnings Before Interest and Income Taxes

1       Includes adjusted EBIT from US Gas Transmission since the completion of the Merger Transaction on February 27, 2017. For additional information, refer to Merger with Spectra Energy.

2       Includes adjusted EBIT from British Columbia Pipeline & Field Services, Spectra Canadian Midstream, Maritimes & Northeast Canada (M&N Canada) and certain other gas pipeline, gathering and storage assets since the completion of the Merger Transaction on February 27, 2017.

3       Includes adjusted EBIT from DCP Midstream since the completion of the Merger Transaction on February 27, 2017.

4       Effective January 1, 2017, adjusted EBIT from Aux Sable, which is comprised of Enbridge’s equity interest in Aux Sable US, Aux Sable Midstream US and Aux Sable Canada, has been grouped with US Midstream. Comparative amounts have been reclassified to facilitate comparison.

5       Effective January 1, 2017, adjusted EBIT from Vector Pipeline and Enbridge Offshore Pipelines (Offshore) have been grouped with Other. Comparative amounts have been reclassified to facilitate comparison.

Additional details on items impacting Gas Pipelines and Processing EBIT include:

·                  US Midstream EBIT for each period reflects changes in unrealized fair value gains and losses on derivative financial instruments used to risk manage commodity price exposures.

US Gas Transmission

The assets that comprise US Gas Transmission were acquired through the Merger Transaction and consist of natural gas transmission and storage assets that are held through SEP. The following indirect ownership interests are reported in this business segment: 75% of Texas Eastern, 68% of Algonquin, 75% of East Tennessee Natural Gas, 59% of M&N U.S., 38% of Gulfstream, and certain other gas pipeline, gathering and storage assets. The US Gas Transmission business primarily provides transmission, storage and gathering of natural gas through interstate pipeline systems for customers in various regions of the midwestern, northeastern and southern United States and in Canada. Demand on the natural gas pipeline and storage systems is seasonal, with the highest throughput occurring during colder periods in the first and fourth quarters, and storage injections occurring primarily during the summer periods.

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The Texas Eastern natural gas transmission system extends approximately 2,735 kilometres (1,700 miles) from producing fields in the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York and includes both onshore and offshore pipelines, compressor stations and three storage facilities. Texas Eastern is also connected to four affiliated storage facilities that are partially or wholly-owned by other entities within the US Gas Transmission business.

The Algonquin natural gas transmission system connects with Texas Eastern’s facilities in New Jersey and extends approximately 402 kilometres (250 miles) through New Jersey, New York, Connecticut, Rhode Island and Massachusetts where it connects to M&N U.S. The system consists of approximately 1,819 kilometres (1,130 miles) of pipeline with associated compressor stations.

East Tennessee’s natural gas transmission system crosses Texas Eastern’s system at two locations in Tennessee and consists of two mainline systems totalling approximately 2,414 kilometres (1,500 miles) of pipeline in Tennessee, Georgia, North Carolina and Virginia, with associated compressor stations. East Tennessee has a LNG storage facility in Tennessee and also connects to the Saltville storage facilities in Virginia.

M&N U.S., which is owned 78% by Enbridge, is an approximately 563 kilometre (350 mile) mainline interstate natural gas transmission system, including associated compressor stations, which extends from the border of Canada near Baileyville, Maine to northeastern Massachusetts. M&N U.S. is connected to the Canadian portion of the Maritimes & Northeast Pipeline system, M&N Canada (see Gas Pipelines and Processing – Canadian Midstream).

Gulfstream is an approximately 1,199 kilometre (745 mile) interstate natural gas transmission system, with associated compressor stations, operated jointly by SEP and The Williams Companies, Inc. (Williams). Gulfstream transports natural gas from Mississippi, Alabama, Louisiana and Texas, crossing the Gulf of Mexico to markets in central and southern Florida. Gulfstream is owned 50% directly by SEP and 50% by affiliates of Williams and is accounted for under the equity method of accounting.

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

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

Business Risks

The risks identified below are specific to US Gas Transmission. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks in Enbridge’s MD&A for the year ended December 31, 2016.

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Asset Utilization

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

Seasonal Price Spreads

The supply increase has also had a negative impact on the seasonal price spreads historically seen between the summer and winter months. The value of storage assets and contracts has declined in recent years, negatively affecting the results from the Company’s storage facilities.

Economic Regulation

US Gas Transmission is subject to laws and regulations at the federal and state levels. Regulations applicable to the natural gas transmission and storage industries have a significant effect on the nature of the businesses and the manner in which they operate. Changes to regulations are ongoing and the Company cannot predict the future course of changes in the regulatory environment or the ultimate effect that any future changes will have on its businesses.

Competition

The US Gas Transmission business competes with similar facilities that serve the same supply and market areas in the transmission and storage of natural gas. The principal elements of competition are location, rates, terms of service, flexibility and reliability of service. The natural gas transported in the US Gas Transmission business also competes with other forms of energy available to the Company’s customers and end-users, including electricity, coal, propane and fuel oils.

Results of Operations

US Gas Transmission adjusted EBIT for the three and six months ended June 30, 2017, reflected results of operations since the completion of the Merger Transaction on February 27, 2017. When compared to pre-Merger results from the prior year, US Gas Transmission’s operating results include higher earnings primarily from business expansion projects on Algonquin Gas Transmission, Sabal Trail Transmission and Texas Eastern Transmission.

Canadian Midstream

Upon completion of the Merger Transaction on February 27, 2017, Canadian Midstream now also includes the Western Canada Transmission & Processing businesses, which comprise British Columbia Pipeline & Field Services, Canadian Midstream, M&N Canada and certain other gas pipeline, gathering and storage assets. British Columbia Pipeline and British Columbia Field Services provide fee-based natural gas transmission and gas gathering and processing services. British Columbia Pipeline has approximately 2,816 kilometres (1,750 miles) of transmission pipeline in British Columbia and Alberta, as well as associated mainline compressor stations. The British Columbia Field Services business includes eight gas processing plants located in British Columbia associated field compressor stations and approximately 2,253 kilometres (1,400 miles) of gathering pipelines. Canadian Midstream provides similar gas gathering and processing services in British Columbia and Alberta and consists of nine natural gas processing plants and approximately 966 kilometres (600 miles) of gathering pipelines. M&N Canada is an approximately 885 kilometre (550 mile) interprovincial natural gas transmission mainline system which extends from Goldboro, Nova Scotia to the United States border near Baileyville, Maine. M&N Canada is connected to M&N U.S. – refer to US Gas Transmission. Enbridge has an approximate 78% interest in M&N Canada.

The majority of transportation services are provided by British Columbia Pipeline under firm agreements, which provide for fixed reservation charges that are paid monthly regardless of actual volumes transported on the pipeline, plus a small variable component that is based on volumes transported to recover variable costs. British Columbia Pipeline also provides interruptible transmission services where customers can use capacity if it is available at the time of request. Payments under these services are based on volumes transported. Natural gas gathering and processing services are provided under fee-for-service contracts.

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Business Risks

The risks identified below are specific to the Western Canada Transmission & Processing businesses. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks in Enbridge’s MD&A for the year ended December 31, 2016.

Competition

Western Canada Transmission & Processing businesses compete with third-party midstream companies, producers and pipelines in the gathering, processing and transmission of natural gas. The principal elements of competition are location, rates, terms of service, and flexibility and reliability of service.

Asset Utilization

Western Canada Transmission & Processing businesses provide services under fee-for-service contracts and its revenues are not directly exposed to commodity price risk. However, the sustained decline in natural gas prices has reduced producer demand for both expansions of the British Columbia gas processing plants as well as renewals of existing gas processing contracts, and this trend could continue if prices remain below historical norms.

Results of Operations

Canadian Midstream adjusted EBIT for the three and six months ended June 30, 2017, reflected the results of operations from the new assets acquired through the Merger Transaction as described above. The three and six months ended June 30, 2017 increase in Canadian Midstream adjusted EBIT also reflected contributions from the Tupper Plants acquired in April 2016.

When compared to pre-Merger results from the corresponding periods in 2016, Canadian Midstream results include a decrease in firm revenue primarily as a result of shipper contract renewals at lower volumes as well as an increase in operating and maintenance costs, partially offset by higher interruptible revenues and incremental revenues from volumes that exceeded take-or-pay levels due to robust producer activity within Canadian Midstream’s footprint.

Alliance Pipeline

Alliance Pipeline adjusted EBIT for the three and six months ended June 30, 2017, which comprises equity earnings from the Company’s 50% equity investment in Alliance Pipeline, was comparable with the corresponding 2016 periods.

US Midstream

Upon completion of the Merger Transaction on February 27, 2017, US Midstream now also includes a 50% investment in DCP Midstream, which is accounted for as an equity investment. DCP Midstream gathers, compresses, treats, processes, transports, stores and sells natural gas. It also produces, fractionates, transports, stores and sells NGLs, recovers and sells condensate, and trades and markets natural gas and NGLs. Phillips 66 owns the other 50% interest in DCP Midstream.

DCP Midstream owns or operates assets in 17 states in the United States including approximately 102,998 kilometres (64,000 miles) of gathering and transmission pipeline, 61 natural gas processing plants and 12 fractionation facilities. In addition, DCP Midstream operates a propane wholesale marketing business and an eight-million barrel propane and butane storage facility in the northeastern United States. DCP Midstream also holds a 33.3% interest in the Sand Hills and Southern Hills NGL pipelines.

DCP Midstream is exposed to similar business risks as the Company’s existing US Midstream assets as disclosed in Enbridge’s MD&A for the year ended December 31, 2016.

Purchase, Service and Sales Agreements

DCP Midstream sells a portion of its NGLs to Phillips 66 and Chevron Phillips Chemical Company LLC (CPChem). In addition, DCP Midstream purchases NGLs from CPChem. Approximately 26% of DCP Midstream’s NGL production was committed to Phillips 66 and CPChem as at June 30, 2017, under contracts expiring in January 2019. DCP Midstream anticipates continuing to purchase and sell commodities with Phillips 66 and CPChem, in the ordinary course of business.

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The residual natural gas, primarily methane, that results from processing raw natural gas is sold at market-based prices to marketers and end-users, including large industrial companies, natural gas distribution companies and electric utilities. DCP Midstream purchases or takes custody of substantially all of its raw natural gas from producers, principally under percentage-of-proceeds/index arrangements, keep-whole and wellhead purchase agreements and fee-based arrangements. More than 75% of the volumes of gas that are gathered and processed are under percentage-of-proceeds contracts. Percentage-of-proceeds arrangements typically result in DCP Midstream gathering, processing and selling natural gas that has been purchased from producers. The residue natural gas and NGLs are sold based on index prices from published index market prices. DCP Midstream remits to the producers either an agreed-upon percentage of the actual proceeds received by DCP Midstream or an agreed-upon percentage of the proceeds based on index-related prices or contractual recoveries, regardless of the actual amount of sales proceeds. DCP Midstream’s revenues from percentage-of-proceeds/index arrangements are directly related to the prices of natural gas, NGLs or condensate.

Results of Operations

US Midstream incurred a higher adjusted loss before interest and income taxes for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods. The increase in adjusted loss before interest and income taxes for the three and six months ended June 30, 2017, was primarily attributable to lower volumes on the Company’s US Midstream assets that are held by MEP, as a result of the continued low commodity price environment which resulted in reduced drilling by producers. Partially offsetting this negative effect was higher contributions from Aux Sable US due to increased fractionation margins, as well as a contribution from the Company’s investment in DCP Midstream that was acquired through the Merger Transaction. Post completion of the Merger Transaction, DCP Midstream contributed $23 million and $28 million to US Midstream adjusted EBIT for the three and six months ended June 30, 2017, respectively.

Other

Other adjusted EBIT increased for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods, primarily reflecting positive contributions from Offshore as a result of an increase in transportation rates on Heidelberg Oil Pipeline and an increase in variable rate revenues on Walker Ridge Gas Gathering System.

GAS DISTRIBUTION

Earnings Before Interest and Income Taxes

1       Includes adjusted EBIT from Union Gas since the completion of the Merger Transaction on February 27, 2017. For additional information, refer to Merger with Spectra Energy.

2       Effective January 1, 2017, the Company no longer adjusts for the impact of weather in the determination of its adjusted EBIT.

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EGD

As EGD’s operations are rate-regulated and its revenues are directly impacted by items such as depreciation, financing charges and current income taxes, the adjusted EBIT measure for EGD is less indicative of business performance. In light of the nature of the regulated model for EGD’s business, the following supplemental adjusted earnings information is provided to facilitate an understanding of EGD’s results from operations:

EGD Earnings

EGD adjusted earnings increased in the second quarter of 2017, compared with the corresponding 2016 period, primarily due to lower employee and pension related costs, and higher distribution charges, partially offset by warmer weather.

EGD adjusted earnings decreased in the first half of 2017, compared with the corresponding 2016 period. The increase in the second quarter of 2017, as discussed above, was more than offset by weaker first quarter results. First quarter results in 2017 decreased, compared with the corresponding 2016 period, primarily due to higher earnings sharing in 2017, higher depreciation expense resulting from a higher overall asset base and lower capitalized interest due to the completion of the Greater Toronto Area project in March 2016.

Adjusted earnings for EGD was also lower for the six months ended June 30, 2017, relative to the comparable period in 2016, as a result of a change in practice with respect to weather normalization. Prior to January 1, 2017, the impacts of warmer/colder than normal weather were removed for the purposes of EGD adjusted earnings. Effective January 1, 2017, the Company discontinued this practice, and as such, EGD adjusted earnings reflected lower distribution revenues due to the impacts of warmer than normal weather during the three and six months ended June 30, 2017. If the Company had continued with the above noted weather normalization treatment, EGD adjusted earnings would have increased by $2 million and $23 million, for the three and six months ended June 30, 2017, respectively.

Union Gas

Union Gas is a major Canadian natural gas storage, transmission and distribution company based in Ontario with over 100 years of operations and service to customers. The distribution business serves approximately 1.5 million residential, commercial and industrial customers in more than 400 communities across northern, southwestern and eastern Ontario. Union Gas’ storage and transmission business offers storage and transmission services to customers at the Dawn Hub, the largest integrated underground storage facility in Canada and one of the largest in North America. It offers customers an important link in the movement of natural gas from western Canada and United States supply basins to markets in central Canada and the northeast United States.

Union Gas’ distribution system consists of approximately 64,374 kilometres (40,000 miles) of main and service pipelines. Union Gas’ underground natural gas storage facilities have a working capacity of approximately 165 billion cubic feet in 25 underground facilities located in depleted gas fields. Its transmission system consists of approximately 4,828 kilometres (3,000 miles) of high pressure pipeline and associated mainline compressor stations.

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As with EGD, Union Gas’ distribution system is regulated by the Ontario Energy Board (OEB) and is subject to regulation in a number of areas, including rates. Union Gas provides its infranchise customers with regulated distribution, transmission and storage services and also provides unregulated natural gas storage and regulated transmission services for other utilities and energy market participants, including large natural gas transmission and distribution companies. A substantial amount of Union Gas’ annual transportation and storage revenue is generated by fixed demand charges.

Incentive Regulation Framework

Union Gas’ distribution rates are set under a five-year incentive regulation framework. The incentive regulation framework establishes new rates at the beginning of each year through the use of a pricing formula rather than through the examination of revenue and cost forecasts. The framework allows for:

·                  annual inflationary rate increases, offset by a productivity factor of 60% of inflation, such that the annual net rate escalator in each year is 40% of inflation;

·                  rate increases or decreases in the small volume customer classes where average use declines or increases;

·                  certain adjustments to rates;

·                  the continued pass-through of gas commodity, upstream transportation and demand side management costs;

·                  the additional pass-through of costs associated with major capital investments and certain fuel variances;

·                  an allowance for unexpected cost changes that are outside of management’s control;

·                  equal sharing of tax changes between Union Gas and customers; and

·                  an earnings sharing mechanism that permits Union Gas to fully retain the return on equity from utility operations up to 9.93%, share 50% of any earnings between 9.93% and 10.93% with customers, and share 90% of any earnings above 10.93% with customers. In October 2016, Union Gas filed an application with the OEB for new rates effective January 1, 2017, pursuant to the incentive regulation framework. In December 2016, the OEB approved the application on an interim basis with an implementation date of January 1, 2017, to be included in the Quarterly Rate Adjustment Mechanism. A final rate order is expected after the OEB completes its review of Union Gas’ Cap and Trade Compliance Plan.

Cap and Trade

Similar to EGD, Union Gas is subject to the requirements of the Government of Ontario’s Cap and Trade program, which became effective January 1, 2017. Refer to Gas Distribution – Enbridge Gas Distribution Inc. – Cap and Trade in Enbridge’s MD&A for the year ended December 31, 2016, for more information on this program. In November 2016, Union Gas filed its 2017 Compliance Plan and the OEB issued an interim rate order approving the associated Cap and Trade costs for recovery from customers effective January 1, 2017. The OEB will complete its review of Union Gas’ 2017 Compliance Plan and approve the final rates in 2017.

Business Risks

Union Gas is subject to substantially the same business risks as Enbridge’s other gas distribution assets as disclosed in Enbridge’s MD&A for the year ended December 31, 2016.

Results of Operations

Union Gas’ adjusted EBIT for the three and six months ended June 30, 2017, reflects its results of operations since the completion of the Merger Transaction on February 27, 2017.

Union Gas’ results benefitted mainly from higher transportation revenue from the Dawn-Parkway expansion project, partially offset by lower usage due to warmer weather in the first half of 2017.

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As Union Gas’ operations are rate-regulated and its revenues are directly impacted by items such as depreciation, financing charges and current income taxes, the adjusted EBIT measure for Union Gas is less indicative of business performance. In light of the nature of the regulated model for Union Gas’ business, the following supplemental adjusted earnings information is provided to facilitate an understanding of Union Gas’ results from operations:

Union Gas Earnings1

1       Includes adjusted earnings generated by Union Gas since the completion of the Merger Transaction on February 27, 2017.

Similar to EGD, Union Gas’ adjusted earnings for each period include the impact of warmer/colder than normal weather in their franchise area. If Union Gas made an adjustment for warmer than normal weather, adjusted earnings would have increased by $7 million and $9 million, for the three and six months ended June 30, 2017, respectively.

GREEN POWER AND TRANSMISSION

Earnings Before Interest and Income Taxes

Green Power and Transmission adjusted EBIT increased for the three and six months ended June 30, 2017, compared with the corresponding 2016 periods. The increase in adjusted EBIT reflected stronger Canadian wind resources in the first half of 2017 and stronger United States wind resources in the second quarter of 2017.

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ENERGY SERVICES

Earnings Before Interest and Income Taxes

Following are additional details on items impacting Energy Services EBIT:

·                 Energy Services EBIT for each period reflects changes in unrealized fair value gains and losses related to the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and exposure to movements in commodity prices on the value of inventory.

Energy Services adjusted EBIT for the three and six months ended June 30, 2017, reflected compressed location and quality differentials in certain markets, lower refinery demand for certain products and fewer opportunities to achieve profitable margins on facilities where the Company holds capacity obligations. Adjusted EBIT from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

ELIMINATIONS AND OTHER

Earnings Before Interest and Income Taxes