Exhibit 99.7

ENBRIDGE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS

December 31, 2016

GLOSSARY

ACFFO	Available cash flow from operations
ALJ	Administrative Law Judge
Alliance Pipeline Canada	Canadian portion of Alliance Pipeline
Alliance Pipeline US	United States portion of Alliance Pipeline
Average Exchange Rate	United States to Canadian dollar average exchange rate for a period/year
bcf/d	Billion cubic feet per day
bpd	Barrels per day
Cabin	Cabin Gas Plant
Canadian L3R Program	Canadian portion of the Line 3 Replacement Program
CSR	Corporate Social Responsibility
CTS	Competitive Toll Settlement
EBIT	Earnings before interest and income taxes
ECT	Enbridge Commercial Trust
EELP	Enbridge Energy, Limited Partnership
EEP	Enbridge Energy Partners, L.P.
EGD	Enbridge Gas Distribution Inc.
EGNB	Enbridge Gas New Brunswick Inc.
EIPLP	Enbridge Income Partners LP
Enbridge or the Company	Enbridge Inc.
ENF	Enbridge Income Fund Holdings Inc.
EPAI	Enbridge Pipelines (Athabasca) Inc.
EPI	Enbridge Pipelines Inc.
Federal Court	Federal Court of Appeal
FERC	Federal Energy Regulatory Commission
Flanagan South	Flanagan South Pipeline
GHG	Greenhouse gas
GP	General partner
GTA	Greater Toronto Area
Heidelberg Pipeline	Heidelberg Oil Pipeline
IDR	Incentive Distribution Rights
IJT	International Joint Tariff
L3R Program	Line 3 Replacement Program
Lakehead System	Lakehead Pipeline System
LNG	Liquefied natural gas
MD&A	Management’s Discussion and Analysis
MEP	Midcoast Energy Partners, L.P.
MNPUC	Minnesota Public Utilities Commission
MPC	Marathon Petroleum Corporation
MW	Megawatts
NEB	National Energy Board
NGL	Natural gas liquids
Norlite	Norlite Pipeline System
Northern Gateway	Northern Gateway Project

1

Noverco	Noverco Inc.
Offshore	Enbridge Offshore Pipelines
ORM Plan	Operational Risk Management Plan
PPA(s)	Power purchase agreement(s)
Rampion Project	Rampion Offshore Wind Project
RGP	Rich Gas Premium
ROE	Return on equity
Seaway Pipeline	Seaway Crude Pipeline System
Spectra Energy	Spectra Energy Corp
Stampede Pipeline	Stampede Oil Pipeline
the Certificate(s)	Certificate(s) of Public Convenience and Necessity under the authority of the NEB
the Fund	Enbridge Income Fund
the Fund Group	The Fund, ECT, EIPLP and the subsidiaries and investees of EIPLP
the Tupper Plants	Tupper Main and Tupper West gas plants
U.S. GAAP	Generally accepted accounting principles in the United States of America
U.S. L3R Program	United States portion of the Line 3 Replacement Program
Vector	Vector Pipeline
WCSB	Western Canadian Sedimentary Basin
WTI	West Texas Intermediate

2

MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (MD&A) dated February 17, 2017 should be read in conjunction with the audited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) for the year ended December 31, 2016, prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). 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.

Effective January 1, 2016, Enbridge revised its reportable segments to better reflect the underlying operations of the Company. The Company believes this new format more clearly describes the financial performance of its business segments, provides increased transparency with respect to operational results and aligns with business segment decision making and management.

On May 12, 2016, the Company filed an amended MD&A for the year ended December 31, 2015 to retrospectively apply the revisions to its reportable segments to the 2015 annual MD&A of the Company that was previously filed on February 19, 2016. Revisions to the segmented information presentation included:

·The replacement of the previous segments: Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services; Sponsored Investments; and Corporate with new segments: Liquids Pipelines; Gas Distribution; Gas Pipelines and Processing; Green Power and Transmission; and Energy Services; and

·Presenting the Earnings before interest and income taxes (EBIT) of each segment as opposed to Earnings attributable to Enbridge common shareholders. Amounts related to Interest expense, Income taxes, Earnings attributable to noncontrolling interests and redeemable noncontrolling interests and Preference share dividends are now reported on a consolidated basis.

These changes had no impact on reported consolidated earnings for the years ended December 31, 2015 and 2014.

OVERVIEW

Enbridge, a Canadian company, is a North American leader in delivering energy. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids transportation system. The Company also has significant and growing involvement in natural gas gathering, transmission and midstream businesses. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company and provides distribution services in Ontario, Quebec, New Brunswick and New York State. As a generator of energy, Enbridge has interests in approximately 3,500 megawatts (MW) (2,500 MW net) of renewable and alternative energy generating capacity which is operating, secured or under construction, and the Company continues to expand its interests in wind, solar and geothermal power. Enbridge employs approximately 9,200 people, primarily in Canada and the United States.

The Company’s activities are carried out through five business segments: Liquids Pipelines; Gas Distribution; Gas Pipelines and Processing; Green Power and Transmission; and Energy Services, as discussed below.

LIQUIDS PIPELINES

Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines and terminals in Canada and the United States, including Canadian Mainline, Lakehead Pipeline System (Lakehead System), Regional Oil Sands System, Mid-Continent and Gulf Coast, Southern Lights Pipeline, Bakken System and Feeder Pipelines and Other.

GAS DISTRIBUTION

Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD), which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick and the Company’s investment in Noverco Inc. (Noverco).

3

GAS PIPELINES AND PROCESSING

Gas Pipelines and Processing consists of investments in natural gas pipelines and gathering and processing facilities. Investments in natural gas pipelines include the Company’s interests in Alliance Pipeline, Vector Pipeline (Vector) and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in Aux Sable, a natural gas extraction and fractionation business located near the terminus of the Alliance Pipeline, Canadian Midstream assets located in northeast British Columbia and northwest Alberta and United States Midstream assets located primarily in Texas and Oklahoma.

GREEN POWER AND TRANSMISSION

Green Power and Transmission consists of the Company’s investments in renewable energy assets and transmission facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United States primarily in Colorado, Texas, Indiana and West Virginia. The Company also has assets under development located in Europe.

ENERGY SERVICES

The Energy Services businesses in Canada and the United States undertake physical commodity marketing activity and logistical services, oversee refinery supply services and manage the Company’s volume commitments on various pipeline systems.

ELIMINATIONS AND OTHER

In addition to the segments noted above, Eliminations and Other includes operating and administrative costs and foreign exchange costs which are not allocated to business segments. Also included in Eliminations and Other are new business development activities, general corporate investments and elimination of transactions between segments required to present financial performance and financial position on a consolidated basis.

MERGER AGREEMENT WITH SPECTRA ENERGY

On September 6, 2016 Enbridge and Spectra Energy Corp (Spectra Energy) announced that they had entered into a definitive merger agreement under which Enbridge and Spectra Energy would combine in a stock-for-stock merger transaction (the Merger Transaction), which valued Spectra Energy common stock at approximately $37 billion (US$28 billion), based on the closing price of Enbridge’s common shares on September 2, 2016. The final purchase price for the Merger Transaction may vary based on the market price of Enbridge’s common shares at the time the Merger Transaction is completed. There is no assurance when or if the Merger Transaction will be completed.

The combination will create the largest energy infrastructure company in North America and one of the largest globally based on a pro-forma enterprise value of approximately $165 billion (US$127 billion) as measured at the time of the announcement. The new company would have a substantial capital project portfolio, including $26 billion of commercially secured growth projects through 2019 and a $48 billion probability risk-weighted development project portfolio through 2024. Upon closing of the Merger Transaction, the Company expects to further increase its quarterly common share dividend to approximately 15% above the prevailing quarterly rate of $0.530 per common share in 2016. Also, post closing of the Merger Transaction, the combined capital growth program is expected to deliver ongoing dividend growth of 10%-12% per annum through 2024, while maintaining a payout of 50% to 60% of available cash flow from operations (ACFFO).

Under the terms of the Merger Transaction, Spectra Energy shareholders will receive 0.984 shares of the combined company for each share of Spectra Energy common stock they own. Upon completion of the Merger Transaction, Enbridge shareholders are expected to own approximately 57% of the combined company and Spectra Energy shareholders are expected to own approximately 43%. The combined company will be called Enbridge Inc.

4

The Merger Transaction was unanimously approved by the Boards of Directors of both companies. Shareholders’ approval for both companies was received in December 2016 and both companies continue to work to meet closing conditions, and the required regulatory applications are progressing. Clearance has been received from the Canadian Transportation Agency, the Committee on Foreign Investment in the United States and the United States Federal Trade Commission to complete the Merger Transaction. Additionally, the Ontario Energy Board has communicated that it is satisfied the Merger Transaction does not require its approval. As a standard part of the regulatory approval process for transactions of this type, both companies continue to work closely with the Canadian Competition Bureau to expeditiously conclude its review of the Merger Transaction. Subject to this review and other customary conditions, the Merger Transaction is expected to close in the first quarter of 2017.

ASSETS MONETIZATION PLAN

Concurrent with the announcement of the Merger Transaction, the Company stated its intention to divest approximately $2 billion of assets over a twelve-month period to provide for additional financial flexibility. On December 1, 2016, Enbridge Income Partners LP (EIPLP) completed the sale of the South Prairie Region assets to an unrelated party for cash proceeds of $1.08 billion. The proceeds from the sale will be reinvested in the secured growth capital programs of Enbridge Pipelines (Athabasca) Inc. (EPAI), including the Regional Oil Sands Optimization Project and Norlite Pipeline System (Norlite) project. For further details on the South Prairie Region assets that were sold, refer to Liquids Pipelines – Feeder Pipelines and Other. Also, during the fourth quarter of 2016, the Company entered into agreements to sell approximately $0.6 billion of additional miscellaneous non-core assets and investments, the full proceeds of which Enbridge expects will be realized before the end of the first quarter of 2017.

UNITED STATES SPONSORED VEHICLE STRATEGY

On May 2, 2016, EEP announced that it was evaluating opportunities to strengthen its business in light of the commodity price environment which was particularly impacting the performance of its natural gas gathering and processing assets. As part of this evaluation, EEP was exploring various strategic alternatives for its investments in Midcoast Operating Partners, L.P. and Midcoast Energy Partners, L.P. (MEP).

On January 27, 2017, Enbridge announced that it had entered into a merger agreement through a wholly-owned subsidiary, whereby it will take private MEP by acquiring all of the outstanding publicly-held common units of MEP. Total consideration to be paid by Enbridge for these units will be approximately US$170 million and the transaction is expected to close in the second quarter of 2017.

In addition, as part of the on-going strategic review of EEP, further joint funding actions with EEP were announced. Specifically, Enbridge and EEP entered into an agreement for the joint funding of the United States portion of the Line 3 Replacement Program (U.S. L3R Program), whereby Enbridge and EEP will fund 99% and 1%, respectively, of the project development and construction cost. Enbridge has reimbursed EEP approximately US$450 million for capital expenditures incurred to date on the project and will fund 99% of the expenditures through construction. For additional information on the U.S. L3R Program, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Line 3 Replacement Program – United States Line 3 Replacement Program (EEP). EEP will retain an option to acquire up to 40% of U.S. L3R Program at book value, once the project is completed and in service.

EEP also used a portion of the proceeds reimbursed by Enbridge under the U.S. L3R Program joint funding agreement to acquire an additional 15% interest in the cash generating Eastern Access Project pursuant to an existing joint funding agreement for approximately US$360 million. The strategic review of EEP is ongoing and it is currently expected that any resulting actions will be announced early in the second quarter of 2017. Enbridge will continue working closely with EEP on the strategic review, but any of these anticipated actions are not expected to be material to Enbridge’s projections.

5

CANADIAN RESTRUCTURING PLAN

On September 1, 2015, Enbridge completed the transfer of its Canadian Liquids Pipelines business, held through Enbridge Pipelines Inc. (EPI) and EPAI, and certain Canadian renewable energy assets to the Fund Group (comprising Enbridge Income Fund (the Fund), Enbridge Commercial Trust (ECT), EIPLP and the subsidiaries and investees of EIPLP) for aggregate consideration of $30.4 billion plus incentive distribution and performance rights (the Canadian Restructuring Plan or the Transaction).

The Transaction was a key component of Enbridge’s Financial Optimization Strategy introduced in December 2014, which included an increase in the Company’s targeted dividend payout. It advanced the Company’s sponsored vehicle strategy and supported Enbridge’s 33% dividend increase effective March 1, 2015 and a further 14% dividend increase effective March 1, 2016. The Transaction provided Enbridge with an alternate source of funding for its enterprise wide growth initiatives and enhanced its competitiveness for new organic growth opportunities and asset acquisitions.

In conjunction with the execution of the Transaction, Enbridge adopted a supplemental cash flow metric, ACFFO, which was introduced in the second quarter of 2015 and continues to be a part of the Company’s normal course annual and quarterly reporting of financial performance. ACFFO is used to assess the performance of the Company’s base business and the impact of its growth program. The Company also started expressing its dividend payout range as a percentage of ACFFO rather than adjusted earnings and established a long-term target dividend payout of 40% to 50% of ACFFO. For impacts on the Company’s long-term target payout policy that would result from the Merger Transaction, see Merger Agreement with Spectra Energy above.

CONSIDERATION

Upon closing of the Transaction, Enbridge received $18.7 billion of units in the Fund Group, comprised of approximately $3 billion of ordinary units of the Fund and $15.7 billion of common equity units of EIPLP, which at the time of the Transaction was an indirect subsidiary of the Fund. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion. In addition, a portion of the consideration to be received by Enbridge over time will be in the form of units which carry Temporary Performance Distribution Rights (TPDR). The TPDR are designed to allow Enbridge to capture increasing value from the secured growth embedded within the transferred businesses; however, the cash flows derived from this incentive mechanism will be deferred (until such time as the units become convertible to a class of cash paying units in the fourth year after issuance).

Enbridge will continue to earn a base incentive fee from the Fund Group through management and incentive fees and Incentive Distribution Rights (IDR), which entitle it to receive 25% of the pre-incentive distributable cash flow above a base distribution threshold of $1.295 per unit, adjusted for a tax factor. The base incentive fee is paid out of ECT. Distributions over $1.890 per unit will be paid out of EIPLP. In addition, Enbridge received the TPDR, a distribution equivalent to 33% of pre-incentive distributable cash flow above the base distribution of $1.295 per unit. The TPDR are paid in the form of Class D units of EIPLP and will be issued each month until the later of the end of 2020 or 12 months after the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program) enters service. The Class D unitholders receive a distribution each month equal to the per unit amount paid on Class C units of EIPLP, but to be paid in kind in additional Class D units. Each Class D unit is convertible into a cash paying Class C unit of EIPLP in the fourth year after its issuance.

The ordinary trust units of the Fund (Fund Units), Class A units of EIPLP and the EIPLP Class C units will pay a per unit cash distribution equivalent to the per unit cash distribution that the Fund pays on its units held by Enbridge Income Fund Holdings Inc. (ENF). The Fund Units, EIPLP’s Class C units and existing preferred units of ECT also include an exchange right whereby they may be converted into common shares of ENF on a one-for-one basis.

FINANCING PLAN

To acquire an increasing ownership interest in the Fund Group, ENF’s financing plan contemplates the issuance by ENF of $600 million to $800 million of public equity per year in one or more tranches through 2018 to fund an increasing investment in the Canadian Liquids Pipelines business. Enbridge has agreed to backstop the equity funding required by ENF to undertake the growth program embedded in the assets it acquired in the Transaction. The amount of public equity issued by ENF will be adjusted as necessary to match its capacity to raise equity funding on favourable terms. In November 2015, ENF successfully completed an equity offering of 21.5 million common shares at a price of $32.60 per share for gross proceeds of $700 million. Concurrent with the closing of the equity offering, Enbridge subscribed for 5.3 million common shares at a price of $32.60 per share, for total proceeds of $174 million, on a private placement basis to maintain its 19.9% ownership interest in ENF.

6

On April 20, 2016, ENF completed a public equity offering of 20.4 million common shares at a price of $28.25 per share for gross proceeds of $575 million. Concurrent with the closing of the equity offering, Enbridge subscribed for 5.1 million common shares at a price of $28.25 per share, for total proceeds of $143 million, on a private placement basis to maintain its 19.9% ownership interest in ENF. ENF used the proceeds from the sale of the common shares to subscribe for additional Fund Units at the price of $28.25 per share. The proceeds from the issuance of the Fund Units are being used to fund the secured growth capital programs of EPAI and EPI. On December 1, 2016, EIPLP completed the sale of the Southern Prairie Region assets for total consideration of $1.08 billion. The proceeds will be used to reduce leverage, fund the Fund Group’s secured growth program and displace planned equity issuances in 2017.

DEVELOPMENT OPPORTUNITIES

The Canadian Liquids Pipelines business is expected to have future organic growth opportunities beyond the current inventory of secured projects. The Fund Group has a first right to execute any such projects that fall within the footprint of the Canadian Liquids Pipelines business. Should the Fund Group choose not to proceed with a specific growth opportunity, Enbridge may pursue such opportunity.

ECONOMIC INTEREST

Upon closing of the Transaction, Enbridge’s overall economic interest in the Fund Group, including all of its direct and indirect interests in the Fund Group, was 91.9%. Upon completion of the $700 million common share issuance in November 2015 and $575 million common share issuance in April 2016 discussed above, Enbridge’s economic interest, through its ownership of ENF, decreased to 89.2% and 86.9%, respectively. As at December 31, 2016, Enbridge’s total economic interest in the Fund Group remained at 86.9%. As ENF executes on its financing plan and increases its ownership in the Fund Group over time, Enbridge’s economic interest is expected to decline over time.

FUND GOVERNANCE

Enbridge continues to act as the manager of the Fund Group and operator and commercial developer of the Canadian Liquids Pipelines business. This will ensure continuity of management and operational expertise, with an ongoing commitment to the safe and reliable operation of the system. As a result of its significant ownership interest, Enbridge has the right to appoint a majority of the Trustees of the Board of ECT for as long as the Company holds a majority economic interest in the Fund Group. A standing conflicts committee has been established to review certain material transactions and arrangements where the interests of Enbridge, or its affiliates, and the relevant entity in the Fund Group, or its affiliates, come into conflict.

THE FUND GROUP 2014 DROP DOWN TRANSACTION

In November 2014, the Fund Group completed the acquisition of Enbridge’s 50% interest in the United States portion of Alliance Pipeline (Alliance Pipeline US) and the subscription for and purchase of Class A units of certain Enbridge subsidiaries that indirectly own the Canadian and United States segments of Southern Lights Pipeline (Southern Lights Class A units). The Southern Lights Class A units, which are non-voting and do not confer any governance or ownership rights in Southern Lights Pipeline, provide a defined cash flow stream to the Fund Group. Total consideration for the transaction was approximately $1.8 billion. Enbridge received on closing approximately $421 million in cash and $461 million in the form of preferred units of ECT, an entity within the Fund Group. Under the agreement, Enbridge provided bridge debt financing to the Fund Group in the form of an $878 million long-term note payable by the Fund Group and bearing interest of 5.5% per annum. In November 2014, the Fund Group issued $1,080 million of medium-term notes with a portion of these proceeds used to fully repay the bridge debt financing to Enbridge. The Fund Group also issued $421 million of trust units to ENF to fund the cash component of the consideration. Enbridge applied approximately $84 million of cash to acquire additional common shares of ENF, thereby maintaining its 19.9% interest in ENF. At the time of the transaction, the Fund Group previously owned a 50% investment in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada).

7

The asset transfers described above occurred between entities under common control of Enbridge, and the intercompany gains realized by the selling entities in the year ended December 31, 2014 have been eliminated from the Consolidated Financial Statements of Enbridge. However, as these transactions involved the sale of shares and partnership units, all tax consequences have remained in consolidated earnings and resulted in a charge of $157 million in 2014.

Through this transaction, which essentially resulted in a partial monetization of the assets by Enbridge through sale to noncontrolling interests (being ENF’s public shareholders), Enbridge realized a source of funds of $323 million for the year ended December 31, 2014, as presented within Financing Activities on the Consolidated Statements of Cash Flows.

8

PERFORMANCE OVERVIEW

	Three months ended		Year ended
	December 31,		December 31,
	2016	2015	2016	2015	2014
(millions of Canadian dollars, except per share amounts)
Earnings attributable to common shareholders
Liquids Pipelines	1,389	675	3,557	1,806	1,980
Gas Distribution	150	111	492	455	432
Gas Pipelines and Processing	24	69	171	(229)	467
Green Power and Transmission	30	50	154	177	149
Energy Services	(147)	92	(185)	325	730
Eliminations and Other	(219)	(156)	(148)	(899)	(456)
Earnings before interest and income taxes	1,227	841	4,041	1,635	3,302
Interest expense	(412)	(371)	(1,590)	(1,624)	(1,129)
Income taxes recovery/(expense)	32	(94)	(142)	(170)	(611)
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(406)	76	(240)	410	(203)
Preference share dividends	(76)	(74)	(293)	(288)	(251)
Earnings/(loss) attributable to common shareholders	365	378	1,776	(37)	1,108
Discontinued operations - Gas Pipelines and Processing	-	-	-	-	46
	365	378	1,776	(37)	1,154
Earnings/(loss) per common share	0.39	0.44	1.95	(0.04)	1.39
Diluted earnings/(loss) per common share	0.39	0.44	1.93	(0.04)	1.37
Adjusted earnings
Liquids Pipelines	1,011	949	3,958	3,384	2,592
Gas Distribution	150	128	494	446	391
Gas Pipelines and Processing	95	88	366	336	293
Green Power and Transmission	43	49	165	175	151
Energy Services	(5)	(22)	28	61	42
Eliminations and Other	(96)	(74)	(349)	(246)	(60)
Adjusted earnings before interest and income taxes1	1,198	1,118	4,662	4,156	3,409
Interest expense2	(403)	(372)	(1,545)	(1,273)	(926)
Income taxes2	(136)	(130)	(520)	(486)	(434)
Noncontrolling interests and redeemable noncontrolling interests2	(61)	(48)	(226)	(243)	(225)
Discontinued operations	-	-	-	-	1
Preference share dividends	(76)	(74)	(293)	(288)	(251)
Adjusted earnings1	522	494	2,078	1,866	1,574
Adjusted earnings per common share1	0.56	0.58	2.28	2.20	1.90
Cash flow data
Cash provided by operating activities	1,058	772	5,211	4,571	2,547
Cash provided by/(used in) investing activities	8	(2,262)	(5,192)	(7,933)	(11,891)
Cash provided by financing activities	1	1,457	1,102	2,973	9,770
Available cash flow from operations3
Available cash flow from operations	879	876	3,713	3,154	2,506
Dividends
Common share dividends declared	497	401	1,945	1,596	1,177
Dividends paid per common share	0.530	0.465	2.12	1.86	1.40
Revenues
Commodity sales	6,436	6,074	22,816	23,842	28,281
Gas distribution sales	703	672	2,486	3,096	2,853
Transportation and other services	2,199	2,168	9,258	6,856	6,507
	9,338	8,914	34,560	33,794	37,641
Total assets	85,832	84,515	85,832	84,515	72,741
Total long-term liabilities	47,511	51,362	47,511	51,362	42,190

1	Adjusted EBIT, adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures see page 18.
2	These balances are presented net of adjusting items.
3	ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. ACFFO is a non-GAAP measure that does not have any standardized meaning prescribed by GAAP - see Non-GAAP Measures.

9

EBIT AND EARNINGS/(LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS

EBIT

For the year ended December 31, 2016, EBIT was $4,041 million compared with $1,635 million for the year ended December 31, 2015 and $3,302 million for the year ended December 31, 2014. For the fourth quarter of 2016, EBIT was $1,227 million compared with $841 million for the fourth quarter of 2015.

As discussed below in Adjusted EBIT, the Company has continued to deliver strong earnings growth from a majority of its businesses over the course of the last two years, offset partly in the second quarter of 2016 by the impacts of extreme wildfires in northeastern Alberta discussed in Liquids Pipelines – Impact of Wildfires in Northeastern Alberta. The positive impact of this growth and the comparability of the Company’s earnings for each period are impacted by a number of unusual, non-recurring or non-operating factors that are enumerated in the Non-GAAP Reconciliation tables and discussed in the results for each reporting segment, the most significant of which are summarized below:

·The Company has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks which create 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. For the year ended December 31, 2016, the Company’s EBIT reflected $543 million of unrealized derivative fair value gains, compared with $2,017 million and $36 million of unrealized derivative fair value loss in the corresponding 2015 and 2014 periods.

·EBIT for 2016 reflected an $850 million gain ($520 million after-tax attributable to Enbridge) within the Liquids Pipelines segment related to the disposition of the South Prairie Region assets in December 2016.

·The Company’s 2016 EBIT was also impacted by certain impairment charges reflected within the Liquids Pipelines segment. In the fourth quarter of 2016, the Canadian Federal Government directed the National Energy Board (NEB) to dismiss the Company’s Northern Gateway Project (Northern Gateway) application and the Certificates of Public Convenience and Necessity under the authority of the NEB (the Certificates) have been rescinded. In consultation with potential shippers and Aboriginal equity partners, the Company assessed this decision and concluded that the project cannot proceed as envisioned. After taking into consideration the amount recoverable from potential shippers on Northern Gateway, the Company reflected an impairment of $373 million ($272 million after-tax) in the fourth quarter of 2016.

·In September 2016, EEP announced that it had applied for the withdrawal of the regulatory applications for the Sandpiper Project that were pending with the Minnesota Public Utilities Commission (MNPUC). In connection with this announcement and other factors, the total impairment charge in respect of the Sandpiper Project recorded during the year, including related project costs of $12 million, was $1,004 million, of which $875 million was attributable to noncontrolling interests in EEP and Marathon Petroleum Corporation (MPC), EEP’s partner in the Sandpiper Project ($81 million after-tax in total attributable to Enbridge’s common shareholders).

·In the second quarter of 2016, an impairment charge of $176 million ($103 million after-tax attributable to Enbridge) was recorded relating to Enbridge’s 75% joint venture interest in Eddystone Rail, a rail-to-barge transloading facility located in the greater Philadelphia, Pennsylvania area that delivers Bakken and other light sweet crude oil to Philadelphia area refineries. Due to a significant decrease in price spreads between Bakken crude oil and West Africa/Brent crude oil and increased competition in the region, demand for Eddystone Rail services dropped significantly, resulting in an impairment of this facility.

·EBIT for 2015 was also impacted by a goodwill impairment charge of $440 million ($167 million after-tax attributable to Enbridge) recognized in the second quarter of 2015 related to EEP’s natural gas and NGL businesses. The prolonged decline in commodity prices reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL pipelines and processing systems, which EEP holds directly and indirectly through its partially-owned subsidiary, MEP.

Earnings/(Loss) Attributable to Common Shareholders

For the year ended December 31, 2016, earnings attributable to common shareholders were $1,776 million ($1.95 earnings per common share) compared with a loss of $37 million ($0.04 loss per common share) for the year ended December 31, 2015 and earnings of $1,154 million ($1.39 earnings per common share) for the year ended December 31, 2014.

10

For the quarter ended December 31, 2016, earnings attributable to common shareholders were $365 million ($0.39 earnings per common share) compared with $378 million ($0.44 earnings per common share) for the quarter ended December 31, 2015.

In addition to the factors discussed in EBIT above and in Adjusted EBIT and Adjusted Earnings below, the year-over-year and fourth quarter-over-quarter comparability of earnings/(loss) attributable to common shareholders was impacted by a number of unusual, non-recurring and non-operating factors that are summarized and described under Non-GAAP Reconciliation – EBIT to Adjusted Earnings.

ADJUSTED EBIT

For the year ended December 31, 2016, adjusted EBIT was $4,662 million, compared with adjusted EBIT of $4,156 million for the year ended December 31, 2015. For the fourth quarter ended December 31, 2016, adjusted EBIT was $1,198 million, an increase of $80 million over the corresponding 2015 period.

Growth in consolidated adjusted EBIT year-over-year was largely driven by stronger contributions from the Company’s Liquids Pipelines segment which benefitted from a number of new assets that were placed into service in 2015, the most prominent being the expansion of the Company’s mainline system in the third quarter of 2015, as well as the reversal and expansion of Line 9B and completion of the Southern Access Extension in the fourth quarter of 2015, which provided increased access to the eastern Canada and Patoka markets, respectively. The Company continued to realize throughput growth on the Canadian Mainline, Lakehead System and Regional Oil Sands System primarily due to strong oil sands production growth in western Canada enabled by recently completed pipeline expansion projects. However, the positive effect of increased production and higher capacity on liquids pipelines throughput was partially negated in the second quarter of 2016 by the impact of extreme wildfires in northeastern Alberta which led to a temporary shutdown of certain of the Company’s upstream pipelines and terminal facilities resulting in a disruption of service on Enbridge’s Regional Oil Sands System with corresponding impacts into and out of Enbridge’s downstream pipelines, including Canadian Mainline and the Lakehead System. Reduced system deliveries resulted in a negative impact of approximately $74 million on the Company’s adjusted EBIT for 2016. Growth in Canadian Mainline adjusted EBIT was also partially offset by a combination of a lower average International Joint Tariff (IJT) Residual Benchmark Toll, which decreased effective April 1, 2016, and a lower foreign exchange rate on hedges used to convert Canadian Mainline United States dollar toll revenues to Canadian dollars.

In 2016, the Company also benefitted from stronger adjusted EBIT contributions from the United States Mid-Continent and Gulf Coast systems, 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). Adjusted EBIT from Feeder Pipelines and Other was also higher, reflecting the benefits of a full year of earnings from Southern Access Extension.

These positive trends on consolidated adjusted EBIT were partially offset by the performance of the United States portion of the Bakken System where adjusted EBIT fell primarily due to a lower surcharge on tolls subject to annual adjustment, as well as lower revenues from EEP’s Berthold rail facility as a result of declining volumes on expiry of contracts.

Many of the annual trends discussed above were also factors driving adjusted EBIT growth in the Liquids Pipelines segment in the fourth quarter of 2016, when compared with the fourth quarter of 2015. However, the decrease in Canadian Mainline IJT Residual Benchmark Toll and a lower rate on foreign exchange hedges of United States dollar toll revenue resulted in a decrease in Canadian Mainline adjusted EBIT for the fourth quarter of 2016 compared with the fourth quarter of 2015. In addition, there was a decrease in Mid-Continent and Gulf Coast adjusted EBIT for the fourth quarter of 2016 compared with the corresponding 2015 period, due to a year-over-year decline in demand for services on Spearhead Pipeline.

Within the Gas Distribution segment, EGD, which operates under a five-year customized Incentive Rate Plan approved in 2014, generated higher adjusted EBIT in 2016 primarily due to higher distribution charges arising from growth in EGD’s rate base.

The Gas Pipelines and Processing segment benefitted from operational efficiencies achieved by Alliance Pipeline. The Enbridge Offshore Pipelines’ (Offshore) Heidelberg Oil Pipeline (Heidelberg Pipeline) which was placed into service in January 2016 and Canadian Midstream’s Tupper Main and Tupper West gas plants (the Tupper Plants) which were acquired on April 1, 2016 also contributed to the year-over-year increase in the Gas Pipelines and Processing segment’s adjusted EBIT. The positive effects were partially offset by the impact of lower volumes on US Midstream facilities due to reduced drilling by producers.

11

The Green Power and Transmission segment adjusted EBIT decreased year-over-year as a result of disruptions at certain eastern Canadian wind farms in the first quarter and fourth quarter of 2016 due to weather conditions which caused icing of blades, as well as weaker wind resources experienced at certain facilities in Canada during the first half and fourth quarter of 2016. These negative effects were partially offset by stronger wind resources at the Company’s United States wind farms during the second half of 2016.

Within the Energy Services segment, a decrease in adjusted EBIT in 2016 reflected weaker performance from Energy Services’ Canadian and United States operations during the first half of 2016. The compression of certain crude oil location and quality differentials and the impact of a weaker NGL market drove a year-over-year decrease in adjusted EBIT. This decrease was partially offset by positive contributions from increased crude oil storage opportunities which also resulted in a lower adjusted loss before interest and income taxes for the fourth quarter of 2016 compared with the corresponding 2015 period.

Within Eliminations and Other, a higher realized foreign exchange derivative loss related to settlements under the Company’s foreign exchange risk management program, as well as higher operating and administrative expenses resulted in an increase in year-over-year adjusted loss before interest and income taxes. The realized loss in Eliminations and Other serves to partially offset the positive effect of translating the earnings performance of the United States dollar denominated businesses to Canadian dollars at the prevailing exchange rate, which averaged $1.32 in 2016, and which is reflected in the reported EBIT of the applicable business segments. Operating and administrative expenses, which were higher primarily due to an increase in depreciation expense, resulting from investment in new information technology assets, and lower recoveries from other business segments, also contributed to a higher fourth quarter adjusted loss before interest and income taxes, when compared with the corresponding 2015 period.

For the year ended December 31, 2015, adjusted EBIT was $4,156 million, compared with adjusted EBIT of $3,409 million for the year ended December 31, 2014. The year-over-year growth in consolidated adjusted EBIT was largely driven by stronger contributions from the Liquids Pipelines segment. The Canadian Mainline contribution increased primarily from higher throughput that resulted from strong oil sands production in western Canada combined with strong downstream refinery demand, as well as ongoing efforts by the Company to optimize capacity utilization and to enhance scheduling efficiency with shippers. These positive factors were partially offset by a lower year-over-year average Canadian Mainline IJT Residual Benchmark Toll. The Lakehead System also experienced year-over-year growth in adjusted EBIT, mainly due to higher throughput and tolls, as well as contributions from new assets placed into service in 2014 and 2015, the most prominent being the expansion of the Company’s mainline system completed in July 2015 and the replacement and expansion of Line 6B completed in 2014. In 2015, the Company also benefitted from a full-year of EBIT contributions from Mid-Continent and Gulf Coast, mainly attributed to the Flanagan South and Seaway Twin pipelines, both of which commenced service in late 2014.

12

ADJUSTED EARNINGS

Adjusted earnings for the year ended December 31, 2016 were $2,078 million ($2.28 per common share) compared with $1,866 million for the year ended December 31, 2015 ($2.20 per common share) and $1,574 million ($1.90 per common share) for the year ended December 31, 2014. Adjusted earnings for the fourth quarter of 2016 were $522 million ($0.56 per common share) compared with $494 million ($0.58 per common share) for the fourth quarter of 2015.

The year-over-year increases in adjusted earnings reflected the operating factors as discussed above in Adjusted EBIT. The impacts of extreme wildfires in northeastern Alberta in the second quarter of 2016 on adjusted earnings and adjusted earnings per share for the year ended December 31, 2016 remained unchanged at $26 million and $0.03, respectively.

Partially offsetting the adjusted earnings growth discussed above was higher interest expense over the past two years resulting from debt incurred to fund asset growth and the impact of refinancing construction debt with longer-term debt financing. The amount of interest capitalized year-over-year also decreased as a result of projects coming into service. Preference share dividends were also higher year-over-year resulting from additional preference shares issued in 2014 and in the fourth quarter of 2016 to fund the Company’s growth capital program. For a detailed discussion on the Company’s financing activities, refer to Liquidity and Capital Resources.

Also partially offsetting the adjusted EBIT growth was an increase in adjusted income taxes expense which resulted from higher adjusted earnings. This was partially offset by increased tax benefits associated with certain financing activities, as well as a higher benefit from the effect of rate-regulated accounting for deferred income taxes.

Adjusted earnings attributable to noncontrolling interests and redeemable noncontrolling interests decreased in 2016 compared with 2015. The decrease was driven by a full year of a lower public ownership interest in the Fund Group following the execution of the Canadian Restructuring Plan in the third quarter of 2015. Adjusted earnings attributable to noncontrolling interests were higher in the fourth quarter of 2016 when compared with the fourth quarter of 2015, due to stronger operating performance at EEP primarily as a result of a stronger contribution from its liquids business.

Despite the increase in the Company’s economic interest in the Fund Group in 2015 as a result of the Canadian Restructuring Plan, the adjusted earnings attributable to the Fund Group’s redeemable noncontrolling interests increased in 2015 compared with 2014 as a result of the positive effects of the Canadian Restructuring Plan and the Fund Group 2014 Drop Down Transaction on the Fund Group’s adjusted earnings. For further details, refer to Canadian Restructuring Plan and The Fund Group 2014 Drop Down Transaction.

AVAILABLE CASH FLOW FROM OPERATIONS

ACFFO was $879 million for the three months ended December 31, 2016 compared with $876 million for the three months ended December 31, 2015. ACFFO was $3,713 million for the year ended December 31, 2016 compared with $3,154 million for the year ended December 31, 2015. The quarter-over-quarter and year-over-year change in ACFFO was impacted by the growth in adjusted EBIT as discussed in Adjusted EBIT above, as well as other items discussed below.

Contributing to the year-over-year increase in ACFFO were lower maintenance capital expenditures in 2016 compared with 2015. Over the last few years, the Company has made a significant investment in the ongoing support, maintenance and integrity management of its pipelines and other infrastructure and in the preservation of the service capability of its existing assets. Maintenance capital expenditures decreased in 2016 as higher expenditures in the Company’s Gas Distribution segment were more than offset by lower maintenance capital expenditures in the Liquids Pipelines segment. The lower spending in Liquids Pipelines reflected a shift in the timing of maintenance activities to 2017 on certain leasehold improvements, as well as scope refinements to certain planned maintenance projects resulting from ongoing communication with regulators. The Company plans to continue to invest in its maintenance capital program to support the safety and reliability of its operations.

13

ACFFO also includes cash distributions from the Company’s equity investments. The Company’s distributions from such investments in 2016 were higher compared with 2015 and reflected improved performance of such investments, as well as distributions from assets placed into service in recent years.

Other non-cash adjustments include various non-cash items presented in the Company’s Consolidated Statements of Cash Flows, as well as adjustments for unearned revenues received in each year.

Partially offsetting the items discussed above, which created period-over-period increases in ACFFO, was higher interest expense as discussed in Adjusted Earnings above.

The increase in ACFFO was also partially offset by increased distributions to noncontrolling interests in EEP and to redeemable noncontrolling interests in the Fund Group. A higher per unit distribution and the effects of a strengthening United States dollar versus the Canadian dollar resulted in greater distributions to noncontrolling interests in EEP during the first half of 2016. Higher distributions to redeemable noncontrolling interests in the Fund Group were a result of a higher per unit distribution and increased public ownership in the Fund Group.

ACFFO was $3,154 million for the year ended December 31, 2015 compared with $2,506 million for the year ended December 31, 2014. The year-over-year increase in ACFFO was impacted by the growth in adjusted earnings as discussed in Adjusted EBIT above. Also contributing to the increase in ACFFO in 2015 compared with 2014 was decrease in maintenance capital expenditures due to the completion of specific maintenance programs in 2014 and higher year-over-year cash distributions received from the Company’s equity investments. Partially offsetting these positive effects were higher interest expense and higher preference share dividends, as well as higher current income taxes expense in 2015 primarily attributable to the Company’s ability to carry back tax losses in the 2014 taxation year to recover prior year taxes paid. Also partially offsetting the period-over-period increase in ACFFO were increased distributions to noncontrolling interests in EEP and to redeemable noncontrolling interests in the Fund. Distributions were higher in 2015 compared with the distributions in 2014 mainly as a result of increased public ownership and distributions per unit in EEP and the Fund.

IMPACT OF LOW COMMODITY PRICES

Enbridge’s value proposition is built on the foundation of its reliable business model. The majority of its earnings and cash flow are generated from tolls and fees charged for the energy delivery services that it provides to its customers. Business arrangements are structured to minimize exposure to commodity price movements and any residual exposure is closely monitored and managed through disciplined hedging programs. Commercial structures are typically designed to provide a measure of protection against the risk of a scenario where falling commodity prices indirectly impact the utilization of the Company’s facilities. Protection against volume risk is generally achieved through regulated cost of service tolling arrangements, long-term take-or-pay contract structures and fee for service arrangements with specific features to mitigate exposure to falling throughput.

Smaller components of Enbridge’s earnings are more exposed to the impacts of commodity price volatility. This includes Energy Services, where opportunities to benefit from location, time and quality differentials can be affected by commodity market conditions. They also include the Company’s interest in Aux Sable’s natural gas extraction and fractionation facilities and natural gas gathering and processing businesses held through EEP; however, the impact on Enbridge’s overall financial performance is relatively small and any inherent commodity price risk is mitigated by hedging programs, commercial arrangements and Enbridge’s partial ownership interest.

Benchmark prices for West Texas Intermediate (WTI) crude fell below US$30 per barrel at the beginning of 2016 and have remained volatile as the market seeks to re-balance supply and demand. Prices began to recover throughout the year and have climbed above US$50 per barrel periodically. WTI crude prices averaged US$43 per barrel for 2016 but ended the year above US$53 per barrel. WTI crude prices averaged US$52.50 per barrel in January 2017. Although Enbridge is exposed to throughput risk under the Competitive Toll Settlement (CTS) on the Canadian Mainline and under certain tolling agreements applicable to other liquids pipelines assets, including Lakehead System, the reduction of investment in exploration and development programs by the Company’s shippers is not expected to materially impact the financial performance of the Company. It is expected that existing conventional and oil sands production should be more than sufficient to support continued high utilization of the Company’s mainline system, and in fact, mainline throughput as measured at the Canada/United States border at Gretna, Manitoba saw record throughput of 2.6 million barrels per day (bpd) in the month of December 2016. Also in 2016, the mainline system has continued to be subject to apportionment of heavy crudes, as nominated volumes currently exceed capacity on portions of the system. Due to the nature of the commercial structures described above, Enbridge’s earnings and cash flow are not expected to be materially affected by the current low price environment.

14

The lower oil prices are also causing some sponsors of oil sands development programs to reconsider the timing of previously announced upstream development projects. Cancellation or deferral of these projects would affect longer-term supply growth from the Western Canadian Sedimentary Basin (WCSB). Enbridge’s existing growth capital program described under Growth Projects – Commercially Secured Projects has been commercially secured and is expected to generate reliable and predictable earnings growth through 2019 and beyond. Importantly, after taking into account the potential for some of these projects to be cancelled or deferred in an environment where low prices persist, including EEP’s Sandpiper Project for which regulatory applications were withdrawn in September 2016, Enbridge’s most recent near-term supply forecast reaffirms that the expansions and extensions of its liquids pipeline system that were completed in 2015, as well as the projects currently in progress will provide cost-effective transportation services to key markets in North America and will be well utilized.

In the current low-price environment, Enbridge is working closely with producers to find ways to optimize capacity and provide enhanced access to markets in order to alleviate locational pricing discounts. Examples include the last phase of the Line 6B capacity expansion on EEP’s Lakehead System which was placed into service in June 2016. This expansion, which is the final component of the Eastern Access Program, provides increased access to refineries in the upper midwest United States and eastern Canada. In addition, in February 2017, the Company completed the acquisition of a 27.6% equity interest in the Bakken Pipeline System which, upon completion, will further enhance Enbridge’s strategy of providing efficient market access solutions for Bakken production while providing the opportunity for the implementation of joint tolls with the Energy Transfer Crude Oil Pipeline, and will also enhance market access opportunities for Enbridge’s customers and create a new flow path through the Company’s mainline system to the eastern United States Gulf Coast. For recent developments on this matter, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Bakken Pipeline System.

CASH FLOWS

Cash provided by operating activities was $5,211 million for the year ended December 31, 2016, mainly driven by strong operating performance from the Company’s core assets, particularly from Liquids Pipelines and the cash flow generated from growth projects placed into service in recent years. Cash provided by operating activities was also impacted by changes in operating assets and liabilities as further discussed in Liquidity and Capital Resources.

In 2016, Enbridge completed certain capital market transactions. The funding raised through these transactions, along with additional borrowings from the Company’s credit facilities, cash generated from operations and cash on hand, were more than sufficient to finance the Company’s $5.1 billion of capital expenditures in 2016. These funding and cash resources are also expected to provide financing flexibility for the Company’s growth capital program in 2017.

Highlights of capital market transactions in 2016 include Enbridge’s common shares issuance of approximately $2.3 billion in March and the issuance of $750 million preference shares in November. For the first time in over two years, Enbridge also accessed the United States debt markets, issuing in November 2016, two separate US$750 million tranches of senior notes carrying maturity terms of 10 and 30 years, respectively. In December 2016, Enbridge also issued fixed-to-floating subordinated notes of US$750 million with a maturity of 2077. During 2016, Enbridge, through its sponsored vehicles, issued equity of approximately $0.6 billion. Lastly, Enbridge and its subsidiaries issued approximately $1.1 billion in medium-term notes and extended the average maturity of its secured credit facilities. As discussed in Liquidity and Capital Resources, the Company continues to utilize its sponsored vehicles to enhance its enterprise-wide funding program. To further provide for additional financial flexibility, the Company continued to advance its plan to divest approximately $2 billion of non-core assets over a twelve-month period as discussed under Merger Agreement with Spectra Energy – Assets Monetization Plan. Under this plan, in December 2016, EIPLP completed the sale of the South Prairie Region assets to an unrelated party for cash proceeds of $1.08 billion and the Company also entered into agreements to sell approximately $0.6 billion of additional miscellaneous non-core assets and investments.

15

DIVIDENDS The Company has paid common share dividends in every year since it became a publicly traded company in 1953. In January 2017, the Company announced a 10% increase in its quarterly dividend to $0.583 per common share, or $2.332 annualized, effective March 1, 2017.

As described under Merger Agreement with Spectra Energy, upon close of the Merger Transaction, the Company expects to further increase its quarterly common share dividend by an amount sufficient to bring the aggregate increase in the quarterly dividend to approximately 15% above the then prevailing quarterly rate of $0.530 per common share in 2016. For the 10-year period ended December 2016, the Company’s compound annual average dividend growth rate was 13.9%.

As described under the Canadian Restructuring Plan, Enbridge’s current target dividend payout policy range is 40% to 50% of ACFFO. In 2016, the dividend payout was 52.0% (2015 - 50.0%) of ACFFO. For expected impacts to the Company’s dividend payout policy range as a result of the Merger Transaction, refer to Merger Agreement with Spectra Energy.

REVENUES

The Company generates revenues from three primary sources: commodity sales, gas distribution sales and transportation and other services. Commodity sales of $22,816 million for the year ended December 31, 2016 (2015 - $23,842 million; 2014 - $28,281 million) were generated primarily through the Company’s energy services operations. Energy Services includes the contemporaneous purchase and sale of crude oil, natural gas and NGL to generate a margin, which is typically a small fraction of gross revenue. While sales revenues generated from these operations are impacted by commodity prices, net margins and earnings are relatively insensitive to commodity prices and reflect activity levels which are driven by differences in commodity prices between locations, grades and points in time, rather than on absolute prices. Any residual commodity margin risk is closely monitored and managed. Revenues from these operations depend on activity levels, which vary from year to year depending on market conditions and commodity prices.

Gas distribution sales revenues are primarily earned by EGD and are recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through to customers through rates and does not ultimately impact earnings due to its flow-through nature.

Transportation and other services revenues are earned from the Company’s crude oil and natural gas pipeline transportation businesses and also include power production revenues from the Company’s portfolio of renewable and power generation assets. For the Company’s transportation assets operating under market-based arrangements, revenues are driven by volumes transported and the corresponding tolls for transportation services. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator, and in most cost-of-service based arrangements are reflective of the Company’s cost to provide the service plus a regulator-approved rate of return. Higher transportation and other services revenues reflected increased throughput on the Company’s core liquids pipeline assets combined with the incremental revenues associated with assets placed into service over the past two years.

16

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

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 ACFFO; expected future cash flows; financial strength and flexibility; 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 cost and impact to the Company’s overall financial performance of complying with the settlement consent decree related to Line 6B and Line 6A; estimated future dividends; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; the Merger Transaction and expectation regarding the timing and closing thereof; expectations regarding the impact of the Merger Transaction including the combined Company’s scale, financial flexibility, growth program, future business prospects and performance; dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of hedging program; strategic alternatives currently being evaluated in connection with the United States sponsored vehicles strategy and the regulatory framework and recovery of deferred costs by Enbridge Gas New Brunswick Inc. (EGNB).

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, 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 timing and completion of the Merger Transaction, including receipt of regulatory approvals and the satisfaction of other conditions precedent; the realization of anticipated benefits and synergies of the Merger Transaction, governmental legislation, acquisitions and the timing thereof; the success of integration plans; cost of complying with the settlement consent decree related to Line 6B and Line 6A; 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 expected future ACFFO; 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. These factors are relevant to 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, ACFFO 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.

17

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, exchange rates, interest rates, commodity prices, political decisions, supply of and demand for commodities and the settlement consent decree related to Line 6B and Line 6A, 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/(loss), adjusted earnings/(loss) per common share and ACFFO. Adjusted EBIT represents EBIT adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. Adjusted earnings/(loss) represent earnings or loss 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.

ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors.

Management believes the presentation of adjusted EBIT, adjusted earnings/(loss), adjusted earnings/(loss) per share and ACFFO 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/(loss) to set targets and to assess the performance of the Company. Management also uses ACFFO to assess the performance of the Company and to set its dividend payout target. Adjusted EBIT, adjusted EBIT for each segment, adjusted earnings/(loss), adjusted earnings/(loss) per common share and ACFFO 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 summarize the reconciliation of the GAAP and non-GAAP measures.

18

NON-GAAP RECONCILIATIONS

EBIT to Adjusted Earnings

	Three months ended				Year ended
	December 31,				December 31,
	2016		2015		2016		2015		2014
(millions of Canadian dollars)
Earnings before interest and income taxes	1,227		841		4,041		1,635		3,302
Adjusting items:1
Change in unrealized derivative fair value (gains)/loss2	277		79		(543	)	2,017		36
Sandpiper Project asset impairment3	4		-		1,004		-		-
Gain on sale of South Prairie Region assets	(850	)	-		(850	)	-		-
Northern Gateway asset impairment	373		-		373		-		-
Goodwill impairment loss	-		-		-		440		-
Assets and investment impairment loss	56		88		253		108		18
Make-up rights adjustments	(1	)	50		130		42		35
Employee severance and restructuring costs	52		41		82		41		6
Project development and transaction costs	56		2		86		44		17
Unrealized intercompany foreign exchange (gains)/loss	(10	)	(21	)	43		(131	)	(16	)
Northeastern Alberta wildfires pipelines and facilities restart costs	8		-		47		-		-
Warmer/(colder) than normal weather	10		22		18		(15	)	(48	)
Hydrostatic testing	(1	)	23		(15	)	72		-
Leak remediation costs, net of leak insurance recoveries	(11	)	(21	)	(8	)	(26	)	92
(Gains)/loss on sale of non-core assets and investment, net	-		-		4		(88	)	(38	)
Other	8		14		(3	)	17		5
Adjusted earnings before interest and income taxes	1,198		1,118		4,662		4,156		3,409
Interest expense	(412	)	(371	)	(1,590	)	(1,624	)	(1,129	)
Income taxes recovery/(expense)	32		(94	)	(142	)	(170	)	(611	)
(Earnings)/loss attributable to noncontrolling interest and redeemable noncontrolling interests	(406	)	76		(240	)	410		(203	)
Discontinued operations	-		-		-		-		46
Preference share dividends	(76	)	(74	)	(293	)	(288	)	(251	)
Adjusting items in respect of:
Interest expense4	9		(1	)	45		351		203
Income taxes5	(168	)	(36	)	(378	)	(316	)	177
Discontinued operations	-		-		-		-		(45	)
Noncontrolling interests and redeemable noncontrolling interests6	345		(124	)	14		(653	)	(22	)
Adjusted earnings	522		494		2,078		1,866		1,574

1	The above table summarizes adjusting items by nature. For a detailed listing of adjusting items by segment, refer to individual segment discussions.
2	Changes in unrealized derivative fair value gains and loss are presented net of amounts realized on the settlement of derivative contracts during the applicable period.
3	Inclusive of $12 million of related project costs.
4	Interest expense for each period included changes in unrealized derivative fair value gains and losses on interest rate contracts. For the year ended December 31, 2015, interest expense also included a loss of $338 million on de-designation of interest rate hedges from the transfer of assets between entities under common control of Enbridge in connection with the Canadian Restructuring Plan.

19

5

Income Taxes were impacted by adjustments for unusual, non-recurring and non-operating factors as enumerated under adjusting items for earnings before interest and income taxes. For the year ended December 31, 2016, income taxes also included a recovery of $296 million related to an adjustment for a curing loss as described in footnote 6 below. Adjustments for income taxes also included an out-of-period adjustment of $71 million recognized in the first quarter of 2015 in respect of an overstatement of deferred income taxes expense in 2013 and 2014. In the third quarter of 2015, income taxes included an $88 million write-off of a regulatory asset in respect of taxes in connection with the Canadian Restructuring Plan and a valuation allowance of $176 million in respect of deferred income tax assets related to EEP. For the year ended December 31, 2014, income taxes included an expense of $157 million related tax consequences associated with the sale of partnership units between entities under common control of Enbridge. The intercompany gains realized as a result of the transfer between entities were eliminated for accounting purposes, however all tax consequences have remained in consolidated earnings.

6

Noncontrolling interests and redeemable noncontrolling interests were also impacted by adjustments for unusual, non-recurring and non-operating factors as enumerated under adjusting items for earnings before interest and income taxes, as well as adjusting items for interest expense and income taxes. Under EEP’s partnership agreement, capital deficits cannot be accumulated in the capital account of any limited partner and thus, such capital account deficits are brought to zero or “cured”. For the year ended December 31, 2016 , the book value of limited partnership capital accounts in EEP became negative, resulting in a reallocation of such deficit to the Company’s general partnership account in EEP. For the year ended December 31, 2016, earnings attributable to noncontrolling interests were higher by $816 million due to such reallocation. In the case of any additional losses or unanticipated charges to EEP in future periods, curing may occur in such periods.

Adjusted EBIT to ACFFO

To facilitate understanding of the relationship between adjusted EBIT and ACFFO, the following table provides a reconciliation of these two key non-GAAP measures.

	Three months ended				Year ended
	December 31,				December 31,
	2016		2015		2016		2015		2014
(millions of Canadian dollars)
Adjusted earnings before interest and income taxes	1,198		1,118		4,662		4,156		3,409
Depreciation and amortization1	564		541		2,240		2,024		1,577
Maintenance capital2	(205	)	(200	)	(671	)	(720	)	(970	)
	1,557		1,459		6,231		5,460		4,016
Interest expense3	(403	)	(372	)	(1,545	)	(1,273	)	(926	)
Current income taxes3	(31	)	(53	)	(92	)	(160	)	(12	)
Distributions to noncontrolling interests	(182	)	(179	)	(720	)	(680	)	(535	)
Distributions to redeemable noncontrolling interests	(54	)	(34	)	(202	)	(114	)	(79	)
Preference share dividends	(76	)	(74	)	(293	)	(288	)	(245	)
Cash distributions in excess of equity earnings3	67		64		183		244		196
Other non-cash adjustments	1		65		151		(35	)	91
Available cash flow from operations (ACFFO)	879		876		3,713		3,154		2,506
1Depreciation and amortization:
Liquids Pipelines	344		336		1,369		1,227		911
Gas Distribution	88		78		339		308		304
Gas Pipelines and Processing	70		70		292		272		221
Green Power and Transmission	48		47		190		186		124
Energy Services	1		-		2		(1	)	(2	)
Eliminations and Other	13		10		48		32		19
	564		541		2,240		2,024		1,577
2Maintenance capital:
Liquids Pipelines	(76	)	(44	)	(207	)	(278	)	(500	)
Gas Distribution	(88	)	(118	)	(339	)	(302	)	(296	)
Gas Pipelines and Processing	(17	)	(17	)	(48	)	(45	)	(62	)
Green Power and Transmission	(2	)	-		(5	)	-		(1	)
Eliminations and Other	(22	)	(21	)	(72	)	(95	)	(111	)
	(205	)	(200	)	(671	)	(720	)	(970	)
3These balances are presented net of adjusting items.

20

Available Cash Flow from Operations

The following table provides a reconciliation of cash provided by operating activities (a GAAP measure) to ACFFO.

	Three months ended				Year ended
	December 31,				December 31,
	2016		2015		2016		2015		2014
(millions of Canadian dollars)
Cash provided by operating activities - continuing operations	1,058		772		5,211		4,571		2,528
Adjusted for changes in operating assets and liabilities1	272		508		362		688		1,777
	1,330		1,280		5,573		5,259		4,305
Distributions to noncontrolling interests	(182	)	(179	)	(720	)	(680	)	(535	)
Distributions to redeemable noncontrolling interests	(54	)	(34	)	(202	)	(114	)	(79	)
Preference share dividends	(76	)	(74	)	(293	)	(288	)	(245	)
Maintenance capital expenditures2	(205	)	(200	)	(671	)	(720	)	(970	)
Significant adjusting items:
Weather normalization	7		16		13		(11	)	(36	)
Project development and transaction costs	44		2		74		44		19
Realized inventory revaluation allowance3	1		(52	)	(345	)	(474	)	-
Employee severance and restructuring costs	43		30		73		30		6
Other items	(29	)	87		211		108		41
Available cash flow from operations (ACFFO)	879		876		3,713		3,154		2,506

1	Changes in operating assets and liabilities include changes in environmental liabilities, net of recoveries.
2	Maintenance capital expenditures are expenditures that are required for the ongoing support and maintenance of the existing pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete or completing their useful lives). For the purpose of ACFFO, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets.
3	Realized inventory revaluation allowance relates to losses on sale of previously written down inventory for which there is an approximate offsetting realized derivative gain in ACFFO.

CORPORATE VISION AND STRATEGY

VISION

Enbridge’s vision is to be the leading energy delivery company in North America. In pursuing this vision, the Company plays a critical role in enabling the economic well-being and quality of life of North Americans, who depend on access to plentiful energy. The Company transports, distributes and generates energy, and its primary purpose is to deliver the energy North Americans need in the safest, most reliable and most efficient way possible.

Among its peers, Enbridge strives to be the leader, which means not only leadership in value creation for shareholders but also leadership with respect to worker and public safety and environmental protection associated with its energy delivery infrastructure, as well as in customer service, community investment and employee satisfaction. Driven by this vision, the Company delivers value for shareholders from a proven and unique value proposition, which combines visible growth, a reliable business model and generation of a dependable and growing income stream.

STRATEGY

The Company’s initiatives centre around eight areas of strategic emphasis in four key focus areas. Strategies are reviewed at least annually with direction from the Company’s Board of Directors.

21

COMMITMENT TO SAFETY AND OPERATIONAL RELIABILITY
EXECUTE	SECURE THE LONGER-TERM FUTURE
Focus on project management Preserve financing strength and flexibility	Strengthen core businesses Enhance strategic growth platforms
MAINTAIN THE FOUNDATION
Uphold Enbridge values Maintain the Company’s social license to operate Attract, retain and develop highly capable people

Commitment to Safety and Operational Reliability

Safety and operational reliability remains the Company’s number one priority and sets the foundation for the strategic plan. The commitment to safety and operational reliability means achieving and maintaining industry leadership in safety (process, public and personal) and ensuring the reliability and integrity of the systems the Company operates in order to generate, transport and deliver the energy society counts on and to protect the environment.

Under the umbrella of the Company’s Operational Risk Management Plan (ORM Plan) introduced in 2010, Enbridge has undertaken extensive maintenance, integrity and inspection programs across its pipeline systems. The ORM Plan has resulted in strong improvements in the area of safety and operational risk management, a bolstering of incident response capabilities, employee and public safety protocols and improved communications with landowners and first responders. In addition, an enterprise-wide safety and risk management framework has been implemented to ensure the Company identifies, prioritizes and effectively prevents and mitigates risks across the enterprise. The Company strives to embed a common risk management framework within its operations and those of its joint venture partners. Supporting these initiatives is a safety culture that strives towards a target of 100% safe operations, with a belief that all incidents can be prevented. To achieve the goal of industry leadership, the Company measures its performance as compared to standard industry performance, transparently reports its results and continues to use external assessments to measure its performance.

Execute

Focus on Project Management

Enbridge’s objective is to safely deliver projects on time and on budget and at the lowest practical cost while maintaining the highest standards for safety, quality, customer satisfaction and environmental and regulatory compliance. With a significant portfolio of commercially secured growth projects, successful project execution is critical to achieving the Company’s long-term growth plan. These projects are predominantly liquids focused, but increasingly include green energy, natural gas, offshore and gas distribution initiatives. Enbridge, through its Major Projects Group, continues to build upon and enhance the key elements of its rigorous project management processes, including: employee and contractor safety; long-term supply chain agreements; quality design, materials and construction; extensive regulatory and public consultation; robust cost, schedule and risk controls; and efficient project transition to operating units. Ongoing work to ensure Enbridge’s project execution costs remain competitive in any market environment is a priority.

Preserve Financing Strength and Flexibility

The maintenance of adequate financing strength and flexibility is crucial to Enbridge’s growth strategy. Enbridge’s financing strategies are designed to ensure the Company has sufficient financial flexibility to meet its capital requirements. To support this objective, the Company develops financing plans and strategies to manage credit ratings, diversify its funding sources and maintain substantial standby bank credit capacity and access to capital markets in both Canada and the United States. Sponsored vehicles also remain a critical component to ensuring efficient and low-cost access to financial markets. For further discussion on the Company’s financing strategies, refer to Liquidity and Capital Resources.

22

As part of the Company’s risk management policy, the Company engages in a comprehensive long-term economic hedging program to mitigate the impact of fluctuations in interest rates, foreign exchange and commodity price on the Company’s earnings. This economic hedging program together with ongoing management of credit exposures to customers, suppliers and counterparties helps enable cost effective capital raising by supporting one of the key tenets of the Company’s investor value proposition, a reliable business model. For further details, refer to Risk Management and Financial Instruments.

The Company continually assesses ways to generate value for shareholders, including reviewing opportunities that may lead to acquisitions, dispositions or other strategic transactions, some of which may be material. Opportunities are screened, analysed and assessed using strict operating, strategic and financial criteria with the objective of ensuring the effective deployment of capital and the enduring financial strength and stability of the Company.

Secure the Longer-Term Future

A key strategic priority is the development and enhancement of strategic growth platforms from which to secure the Company’s long-term future. As discussed under Merger Agreement with Spectra Energy, on September 6, 2016, Enbridge announced a definitive merger agreement with Spectra Energy. The combined company is expected to benefit from a diversified set of strategic growth platforms, including liquids and gas pipelines, United States and Canadian midstream businesses, an attractive portfolio of regulated natural gas distribution utilities and a growing renewable power generation business. The strength of the combined assets and geographic footprint will generate highly transparent and predictable cash flows underpinned by hiqh-quality commercial constructs that align closely with Enbridge’s investor value proposition and significant on-going organic growth potential.

Strengthen Core Businesses

Within the Company’s pre-merger crude oil transportation business, strategies to strengthen the core business are focused on optimizing asset performance, strengthening stakeholder and customer relationships and providing access to new markets for production from western Canada and the Bakken regions, all while ensuring safe and reliable operations. The Company’s asset optimization efforts focus on maximizing the operational and financial performance of its infrastructure assets within established risk parameters, providing competitive services and value to customers. The Company’s assets are strategically located and well-positioned to capitalize on opportunities. In 2016, despite unfavourable commodity market conditions, Enbridge’s Mainline delivered record volumes of crude into United States markets. The Company’s existing footprint, access to major North American markets, and the ability to incrementally enhance its capacity through low-cost expansions provide Enbridge’s customers with an attractive and reliable path to market.

While executing its record growth capital program in recent years, the Company has also been undertaking an extensive integrity program across its liquids and gas systems. The Line 3 Replacement Program (L3R Program) being undertaken by Enbridge and EEP will support the safety and operational reliability of the mainline system, enhance flexibility, allow Enbridge and EEP to optimize throughput on the mainline system and restore approximately 370,000 bpd of capacity from western Canada into Superior, Wisconsin. For further details on the L3R Program, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Line 3 Replacement Program.

The strategic focus within Regional Oil Sands Systems is to optimize existing asset corridors and provide innovative, creative, competitive and customer oriented solutions to WCSB producers to secure the incremental supply of crude oil expected from the western Canadian oil sands projects over the next decade. Within this regional focus area, Enbridge has approximately $3.7 billion of regional infrastructure growth projects currently under development, including Enbridge’s 70% share of the Norlite project, which is expected to enter service in 2017. In the Bakken region, Enbridge and EEP’s growth is focused on the completion of the US$1.5 billion investment in the Bakken Pipeline System, in partnership with Energy Transfer. The Bakken Pipeline System will provide North Dakota producers enhanced access to premium light crude oil markets in both the eastern and western United States Gulf Coast. For recent developments on this matter, refer to Growth Projects – Commercially Secured Projects– Liquids Pipelines – Bakken Pipeline System (EEP).

23

In addition to executing its secured growth program, the Company is focused on extending growth beyond 2019 through continued expansion of liquids pipelines, as well as development of its current and future natural gas and power businesses. The acquisition of Spectra Energy will provide Enbridge with a leading North American gas infrastructure franchise. Enbridge plans to expand and extend the Spectra Energy gas pipelines to serve growing demand markets in the United States, Canada and Mexico. Natural gas demand is anticipated to grow steadily through the next decade and Spectra Energy’s assets are well positioned for continued profitable expansion.

The Company continues to focus on expanding its Canadian Midstream footprint, primarily within the Montney and Duvernay formations, two of the most competitive natural gas and NGL plays in North America. Even in an environment of depressed prices, the Montney play continues to attract significant drilling activity. In 2016, the Company acquired two operating natural gas plants (the Tupper plants) and associated pipelines in northeastern British Columbia. The Company also continues to pursue ultra-deep water offshore natural gas and crude oil transmission opportunities. In 2016, the Company placed the Heidelberg Pipeline into service and the Stampede Oil Pipeline (Stampede Pipeline) is expected to be operational by 2018. Spectra Energy’s western Canadian franchise adds a very significant scale to Enbridge’s existing Canadian midstream business and it will position Enbridge as the leading gas processing company in the WCSB, with multiple infrastructure expansion and new construction opportunities.

Enbridge’s natural gas distribution business in eastern Canada is the largest in Canada with over two million customers. EGD’s Greater Toronto Area (GTA) project, which was completed in March 2016, is a key component of EGD’s gas supply strategy and will provide new transmission services that will enable access to mid-continent gas supplies for the utility and its customers. Spectra Energy’s Union Gas also operates within a highly attractive franchise area that offers considerable rate-base growth opportunities.

Enhance Strategic Growth Platforms

The development of new platforms to diversify and sustain long-term growth is an important strategic priority. The Merger Transaction goes a long way to achieving Enbridge’s diversification objectives. It will position the Company with approximately 50% non-liquids infrastructure assets. It will also significantly increase Enbridge’s footprint in growing United States markets such as Florida and the Northeast.

The Company will continue focusing on enhancing these new platforms and also on its development and diversification efforts to secure investment in additional renewable energy generation and Liquefied natural gas (LNG) development. Currently, Enbridge is expanding its renewable power efforts offshore of Europe under low-risk commercial structures with highly credit-worthy counterparties. In February 2017, the Company announced it had acquired an effective 50% interest in the partnership that holds the 497-MW Hohe See Offshore Wind Project in Germany, with a targeted in-service date in 2019. In 2016, Enbridge expanded its interests and development expertise in renewable power generation with the acquisitions of a 50% interest in a French offshore wind development company. Along with EDF, Enbridge will co-develop three large scale offshore wind farms off the coast of France that would produce a combined 1,428 MW of power. While development of these projects is still subject to final investment decision and regulatory approvals, the investment significantly extends the Company’s offshore wind generation business which began with the acquisition of a 24.9% interest in the 400-MW Rampion Offshore Wind Project (Rampion Project) in the United Kingdom in 2015. The Rampion Project is anticipated to enter into service in 2018.

The Company’s energy marketing business also plans to expand its business through obtaining capacity on energy delivery and storage assets in strategic locations to grow margins generated from location, grade and time differentials.

24

Maintain the Foundation

Uphold Enbridge Values

Enbridge adheres to a strong set of core values that govern how it conducts its business and pursues strategic priorities, as articulated in its value statement: “Enbridge employees demonstrate integrity, safety and respect in support of our communities, the environment and each other”. Employees are expected to uphold these values in their interactions with each other, customers, suppliers, landowners, community members and all others with whom the Company deals and ensure the Company’s business decisions are consistent with these values. Employees and contractors are required, on an annual basis, to certify their compliance with the Company’s Statement on Business Conduct.

Maintain the Company’s Social License to Operate

Earning and maintaining “social license” - the acceptance by the communities in which the Company operates or is proposing new projects - is critical to Enbridge’s ability to execute on its growth plans. To continually earn public acceptance, the Company is increasingly focused on building long-term relationships by understanding, accommodating and resolving public concerns related to the Company’s projects and operations. The Company engages its key stakeholders through collaboration and by demonstrating openness and transparency in its communication. Enbridge also focuses on enhancing the effectiveness of the Government Relations function with a goal of advocating company positions on key issues and policies that are critical to its business. The Company also strives to build awareness of the role energy and Enbridge play in people’s lives in order to promote better understanding of the Company and its businesses.

To earn the public’s trust, and to help protect and reinforce the Company’s reputation with its stakeholders, Enbridge is committed to integrating Corporate Social Responsibility (CSR) into every aspect of its business. The Company defines CSR as conducting business in an ethical and responsible manner, protecting the environment and the safety of people, providing economic and other benefits to the communities in which the Company operates, supporting universal human rights and employing a variety of policies, programs and practices to manage corporate governance and ensure fair, full and timely disclosure. The Company provides its stakeholders with open, transparent disclosure of its CSR performance and prepares its annual CSR Report using the Global Reporting Initiative G4 sustainability reporting guidelines, which serve as a generally accepted framework for reporting on an organization’s economic, environmental and social performance.

The Company also executes programs and initiatives to ensure the perspective of its stakeholders help guide business decision making on sustainable development issues. With this in mind, in 2016 the Company launched the development of a new generation of environmental goals that reflect the shifting energy landscape in North America, including changing business needs and growing public interest in Enbridge’s role in climate and energy issues. As part of this process, the Company updated its corporate Climate Policy in 2016, to more rigorously outline the steps Enbridge is taking to address climate change, including reducing its own carbon footprint and undertaking activities and engagement with external stakeholders on water protection.

The next generation of Enbridge’s environmental goals will succeed the Company’s Neutral Footprint Program, originally adopted in 2009, through which Enbridge committed to help reduce the environmental impact of its liquids pipeline expansion projects within five years of their occurrence by meeting certain goals for replacing trees, conserving land and generating kilowatt hours of green energy.

Enbridge provides annual progress updates related to the above initiatives in the Company’s annual CSR Reports which can be found at http://csr.enbridge.com. Unless otherwise specifically stated, none of the information contained on, or connected to, the Enbridge website is incorporated by reference in, or otherwise part of, this MD&A.

Attract, Retain and Develop Highly Capable People

Investing in the attraction, retention and development of employees and future leaders is fundamental to executing Enbridge’s growth strategy and creating sustainability for future success. In 2016, Enbridge launched its Building Our Energy Future program, which is aimed to improve and enhance the Company’s competitiveness in the industry so it can continue to serve its stakeholders well and further strengthen its foundation for the future. As one of the initiatives under this program, the Company redesigned its organizational structure around new operating models for service delivery. As a consequence, in October 2016 the Company reduced its workforce by approximately 5%.

25

The Company focuses on enhancing the capability of its people to maximize the potential of the organization and undertakes various activities such as offering accelerated leadership development programs, enhancing career opportunities and building change management capabilities throughout the enterprise so that projects and initiatives achieve intended benefits. Furthermore, Enbridge strives to maintain industry competitive compensation and retention programs that provide both short-term and long-term performance incentives to its employees.

INDUSTRY FUNDAMENTALS

SUPPLY AND DEMAND FOR LIQUIDS

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

As discussed in Performance Overview – Impact of Low Commodity Prices, the downturn in price has impacted Enbridge’s liquids pipelines’ customers, who have responded by reducing their exploration and development spending for 2016 and into 2017. The international market for crude oil has seen a significant increase in production from North American basins and increased production from the Organization of Petroleum Exporting Countries (OPEC) in the face of slower global demand growth. Benchmark prices for WTI crude fell below US$30 per barrel at the beginning of 2016 and have remained volatile as the market seeks to re-balance supply and demand. Prices began to recover throughout the year, in response to anticipated cuts in OPEC country production among other factors, and have climbed above US$50 per barrel for short periods of time. WTI crude prices averaged US$43 per barrel for 2016 and ended the year above US$53 per barrel, with WTI crude prices averaging US$52.50 per barrel in January 2017.

Notwithstanding the low price environment, the Enbridge mainline system has thus far continued to be highly utilized and in fact, mainline throughput as measured at the Canada/United States border at Gretna, Manitoba saw record throughput of 2.6 million bpd in the month of December 2016. The mainline system continues to be subject to apportionment of heavy crudes, as nominated volumes currently exceed capacity on portions of the system. The impact of low crude oil prices on the financial performance of Enbridge’s liquids pipelines business is expected to be relatively modest given the commercial arrangements which underpin many of the pipelines that make up the liquids system and provide a significant measure of protection against volume fluctuations. In addition, the Company’s mainline system is well positioned to continue to provide safe and efficient transportation which will enable western Canadian and Bakken production to reach attractive markets in the United States and eastern Canada at a competitive cost relative to other alternatives. The fundamentals of oil sands production and low crude oil prices have caused some sponsors to reconsider the timing of their upstream oil sands development projects. However, recently updated forecasts continue to reflect long-term supply growth from the WCSB, although the projected pace of growth is slower than previous forecasts as companies continue to assess the viability of certain capital investments in the current low price environment.

Over the long term, global energy consumption is expected to continue to grow, with the growth in crude oil demand primarily driven by emerging economies in regions outside the Organization for Economic Cooperation and Development (OECD), mainly India and China. While OECD countries, including Canada, the United States and western European nations, will experience population growth, the emphasis placed on energy efficiency, conservation and a shift to lower carbon fuels, such as natural gas and renewables, will reduce crude oil demand over the long term. Accordingly, there is a strategic opportunity for North American producers to grow production to displace foreign imports and participate in the growing global demand outside North America.

26

In terms of supply, long-term global crude oil production is expected to continue to grow through 2035, with growth in supply primarily contributed by North America, Brazil and OPEC. Growth in North America is largely driven by production from the oil sands and the continued development of tight oil plays including the Permian, Bakken and Eagle Ford formations. Growth in supply from OPEC is primarily a result of a shift in OPEC’s strategy from ‘balancing supply’ to ‘competing for market share’ in Asia and Europe. However, political uncertainty in certain oil producing countries, including Libya and Iraq, increases risk in those regions’ supply growth forecasts and makes North America one of the most secure supply sources of crude oil. As witnessed throughout 2016 and early 2017, North American supply growth can be influenced by macro-economic factors that drive down the global crude prices. OPEC has since changed its strategy after its November 2016 meeting in which OPEC agreed to cut production by 1.2 million bpd effective January 2017. Over the longer term, North American production from tight oil plays, including the Bakken, is expected to grow as technology continues to improve well productivity and reduce costs. The WCSB, in Canada, is viewed as one of the world’s largest and most secure supply sources of crude oil. However, the pace of growth in North America and level of investment in the WCSB could be tempered in future years by a number of factors including a sustained period of low crude oil prices and corresponding production decisions by OPEC, increasing environmental regulation, prolonged approval processes for new pipelines and the continuation of access restrictions to tide-water in Canada for export.

In recent years, the combination of relatively flat domestic demand, growing supply and long-lead time to build pipeline infrastructure led to a fundamental change in the North American crude oil landscape. The inability to move increasing inland supply to tide-water markets resulted in a divergence between WTI and world pricing, resulting in lower netbacks for North American producers than could otherwise be achieved if selling into global markets. The impact of price differentials has been even more pronounced for western Canadian producers as insufficient pipeline infrastructure resulted in a further discounting of Alberta crude against WTI. With a number of market access initiatives completed by the industry in recent years, including those introduced by Enbridge, the crude oil price differentials significantly narrowed in 2015, and resulted in higher netbacks for producers. The differentials between WTI and world pricing remained narrow in 2016. This has resulted in crude oil continuing to move off of alternative transportation networks such as rail to fill the additional pipeline capacity as it became available. However, Canadian pipeline export capacity is expected to remain essentially full, resulting in incremental production utilizing non-pipeline transportation services until such time as pipeline capacity is made available. As the supply in North America continues to grow, the growth and flexibility of pipeline infrastructure will need to keep pace with the sensitive demand and supply balance. Over the longer term, the Company believes pipelines will continue to be the most cost-effective means of transportation in markets where the differential between North American and global oil prices remain narrow. Utilization of rail to transport crude is expected to be substantially limited to those markets not readily accessible by pipelines.

Enbridge’s role in helping to address the evolving supply and demand fundamentals and alleviating price discounts for producers and supply costs to refiners is to provide expanded pipeline capacity and sustainable connectivity to alternative markets. As discussed in Growth Projects – Commercially Secured Projects, in 2016, Enbridge continued to execute its growth projects plan in furtherance of this objective.

SUPPLY AND DEMAND FOR NATURAL GAS AND NGL

Global energy demand is expected to increase 30% by 2040, according to the International Energy Agency, driven primarily by economic growth in non-OECD countries. Natural gas will play an important role in meeting this energy demand as gas consumption is anticipated to grow by 50% during this period as one of the world’s fastest growing energy sources, second only to renewables. Most natural gas demand will stem from the need for greater power generation capacity, as natural gas is a cleaner alternative to coal, which currently has the largest market share for power generation. Within North America, United States natural gas demand growth is expected to be driven by the next wave of gas-intensive petrochemical facilities which are now starting to enter service, along with power generation, an increase in the volume of LNG exports and additional pipeline exports to Mexico. Within Canada, natural gas demand growth is expected to be largely tied to oil sands development and growth in gas-fired power generation. Canadian gas demand growth will be accelerated with implementation of proposed government regulations to replace coal fired power, designed to meet emissions targets.

27

North American supply from tight formations continues to create a demand and supply imbalance for natural gas and some NGL products. North American gas supply continues to be significantly impacted by development in the northeastern United States, primarily the prolific Marcellus shale, and the rapidly growing Utica shale. The abundance of supply from these shale plays continues to fundamentally alter natural gas flow patterns in North America, as this region has largely displaced flows from the Gulf Coast and WCSB that historically supplied to eastern markets. Similar pressures are also being felt in the Midwest and southern markets. Additional production is expected from this region as pipeline constraints are eliminated, with several proposed pipeline projects targeted for in-service over the next two years.

Natural gas production from regions other than the northeastern United States has largely been flat or has declined over the past several years in the face of lower-cost production from the Appalachian region, in addition to prolonged weak North American natural gas prices. The extended low commodity price environment in the basins in which the US Midstream business operates has resulted in reduced drilling activity and low volumes on the US Midstream business’s systems. One exception is WCSB production, reaching an all-time record high in early 2016, which was triggered by the combination of new infrastructure and the connection of previously drilled wells. Producers remain focused on the Montney shale and the developing Duvernay, where core areas are among the most competitive within North America. Economic drivers vary, but include: continuous productivity improvements, extremely low cost dry gas plays and abundant liquids and/or condensate rich gas resources, where liquid products enhance or drive economics. The highly prolific Permian Basin in West Texas/Southeast New Mexico is also experiencing significant benefit from technology improvements, where producer focus is primarily crude oil, however, with significant production of NGL-rich associated gas. In the longer term, while low natural gas prices are expected to be a key driver in future natural gas demand and infrastructure growth, producer break-even costs continue to decline and as a result it is expected there will continue to be ample economic supply that will respond quickly to rising demand, thereby limiting price advances.

Natural gas prices have been relatively weak over the last year as a result of warm weather and high storage inventories; however, although rig counts have trended lower, production levels have remained generally flat due to productivity gains, the high number of drilled and uncompleted wells and continued focus on liquids-rich and condensate plays. NGL that can be extracted from liquids-rich gas streams include ethane, propane, butane and natural gasoline, which are used in a variety of industrial, commercial and other applications. The robust gas production has created regional supply imbalances for some NGL products and weakened the economics of NGL extraction, although these imbalances modestly improved over the second half of 2016 as crude prices have rebounded and NGL export capacity has expanded.

Over the longer term, the growth in NGL demand is expected to be robust, driven largely by incremental ethane demand. Ethane is the key feedstock to the United States Gulf Coast petrochemical industry, which is the world’s second lowest-cost ethylene production region and is currently undergoing significant expansion that has started to enter service and will accelerate in 2017. When this new infrastructure is completed and fully online in late 2018, ethane prices and resulting extraction margins are expected to improve, reducing the amount of ethane retained in the gas stream. In addition, the inaugural export cargo of ethane was shipped in March 2016 and if waterborne exports rise significantly, the ethane market will further tighten. Similarly, rapidly growing supplies of propane have been outpacing demand leading to record storage levels and downward pressure on prices. The outlook for abundant propane supplies in excess of domestic demand has prompted the development and expansion of export facilities for liquefied petroleum gas (LPG). Over a few short years, the United States has become the world’s largest LPG exporter, with volumes reaching over one million bpd at times in 2016, which have helped to reduce the inventory overhang and provide support to propane prices.

In Canada, the WCSB is well-situated to capitalize on the evolving NGL fundamentals over the longer term as the Montney and Duvernay shale plays contain significant liquids-rich resources at competitive extraction costs. Longer-term, NGL fundamentals indicate a positive outlook for demand growth, and would be further supported with a continued recovery in crude oil prices. Consequently, the crude-to-gas price ratio is expected to remain well above energy conversion value levels and continue to be supportive of NGL extraction over the longer term.

28

Conditions for western Canadian LNG exports remain favourable, as industry proponents continue to assess updated project economics considering a scale down in construction costs, ample low-cost gas supplies and a stabilizing market, as supply/demand forecasts show signs of rebalancing. Proponents who have the benefit of an integrated model (upstream supply and downstream market) have the greatest probability of making a favourable final investment decision. There continues to be regional opposition to proposed projects in general, primarily stemming from a climate change/greenhouse gas (GHG) emissions agenda, mixed with some local Indigenous opposition as it relates to environmental impacts on wildlife and fish habitats. The Government of British Columbia continues to advocate strongly for west coast LNG. The short term outlook for LNG fundamentals points to a continued oversupply, as it will take some time for the market to fully absorb the large volumes of new supply coming online. Post-2025, forecasts indicate demand will exceed projected supply as growing markets seek to diversify supply sources. This should be supportive of Canadian LNG exports.

In response to these evolving natural gas and NGL fundamentals, Enbridge believes it is well-positioned to provide value-added solutions to producers. Enbridge is responding to the need for regional infrastructure with additional investment in Canadian and United States midstream processing and pipeline facilities. Alliance Pipeline traverses through the heart of key liquids-rich plays in the WCSB and Bakken, and is uniquely positioned to transport liquids-rich gas. Alliance Pipeline has developed new service offerings to best meet the needs of producers and shippers, and demand for transportation services continues to be robust. The focus on liquids-rich gas development also creates opportunities for Aux Sable, an extraction and fractionation facility near Chicago, Illinois near the terminus of Alliance Pipeline, which provides producers with access to premium NGL markets. Vector is also well positioned to deliver increasing Marcellus and Utica production to eastern markets.

SUPPLY AND DEMAND FOR RENEWABLE ENERGY

The power generation and transmission network in North America is expected to undergo significant growth over the next 20 years. On the demand side, North American economic growth over the longer term is expected to drive growing electricity demand, although continued efficiency gains are expected to make the economy less energy-intensive and temper demand growth. On the supply side, impending legislation in Canada is expected to accelerate the retirement of aging coal-fired generation plants, resulting in a requirement for significant new generation capacity. While coal and nuclear facilities will continue to be core components of power generation in North America, gas-fired and renewable energy facilities, including biomass, hydro, solar and wind, are expected to be the preferred sources to replace coal-fired generation due to their lower carbon intensities.

North American wind and solar resources fundamentals remain strong. In the United States there is over 82 gigawatts (GW) of installed wind power capacity and in Canada over 11 GW of installed wind power capacity. Solar resources in southwestern states such as Arizona, California and Nevada are considered to be some of the best in the world for large-scale solar plants and the United States currently has over 35 GW of installed solar photovoltaic capacity. In late 2015, the United States passed legislation extending the availability of certain Federal tax incentives which have supported the profitability of wind and solar projects. However, expanding renewable energy infrastructure in North America is not without challenges. Growing renewable generation capacity is expected to necessitate substantial capital investment to upgrade existing transmission systems or, in many cases, build new transmission lines, as these high quality wind and solar resources are often found in regions that are not in close proximity to markets. In the near-term, uncertainty over the availability of tax or other government incentives in various jurisdictions, the ability to secure long-term power purchase agreements (PPAs) through government or investor-owned power authorities and low market prices of electricity may hinder the pace of future new renewable capacity development. However, continued improvement in technology and manufacturing capacity in the past few years has reduced capital costs associated with renewable energy infrastructure and has also improved yield factors of power generation assets. These positive developments are expected to render renewable energy more competitive and support ongoing investment over the long term.

In Europe, the future outlook for renewable energy, especially from offshore wind in countries with long coastlines and densely populated areas, is very positive. According to the European Wind Energy Association, by 2030, wind energy capacity in Europe is expected to be 320 GW, including 66 GW of offshore capacity. There is also wide public support for carbon reduction targets and broader adoption of renewable generation across all governmental levels. Furthermore, governments in Europe are seeking to rationalize the contribution of nuclear power to the overall energy mix, which has resulted in an increased focus on alternative sources such as large scale offshore wind.

29

Enbridge continues to expand its renewable asset footprint and is one of Canada’s largest wind and solar power generators. In February 2017, the Company announced it had acquired an effective 50% interest in the partnership that holds the 497-MW Hohe See Offshore Wind Project in Germany. Earlier in 2016, Enbridge announced the acquisition of the 249-MW Chapman Ranch Wind Project in Texas, as well as the acquisition of a 50% interest in a French offshore wind development company, Éolien Maritime France SAS (EMF). In late 2015, Enbridge announced acquisitions of the 103-MW New Creek Wind Project in West Virginia and a 24.9% interest in the 400-MW Rampion Project in the United Kingdom. The New Creek Wind Project was subsequently completed and placed into service in December 2016. Including these acquisitions, Enbridge has invested over $5 billion in renewable power generation and transmission since 2002. The Company will continue to seek new opportunities to expand its power generation business and growing its portfolio by investing in assets that meet its investment criteria.

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

A key element of Enbridge’s corporate strategy is the successful execution of its growth capital program. In 2016, Enbridge successfully placed into service over $2 billion of growth projects across several business units. With approximately $10 billion of growth projects placed into service over the last two years, Enbridge portfolio of approximately $27 billion of growth projects includes $17 billion of growth projects expected to be placed into service between 2017 and 2019.

In 2016, within the Liquids Pipelines segment, EEP completed and placed into service the expansion of Line 6B on the Lakehead System. This expansion, which is the final component of the Company’s Eastern Access Program, provides increased access to refineries in the upper midwest United States and eastern Canada. EEP also continued to execute on the Lakehead System Mainline Expansion through completion of additional tankage on the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois.

In 2017, the Company expects to place into service approximately $5.6 billion of growth projects, inclusive of Enbridge’s 70% share of the $1.3 billion Norlite project, as well as the Company’s investment in the Bakken Pipeline System. In January 2017, the Company completed the Athabasca Pipeline Twin portion of the Regional Oil Sands Optimization Project, whereas the Wood Buffalo Extension component is now expected to be in service in December 2017. Beyond 2017, the Company will continue to execute its liquids pipelines market access strategy through the completion of the L3R Program.

Within the Gas Distribution segment, the completion of the GTA project in 2016 has enabled EGD to meet the growing demand for natural gas distribution services in the GTA while ensuring the ongoing safe and reliable delivery of natural gas to its current and future customers. The system expansion is the largest ever undertaken by EGD and it significantly bolsters EGD’s rate base and expected earnings going forward.

In 2016, Enbridge also expanded its natural gas pipelines and processing businesses with the acquisition of the Tupper Plants and associated pipelines in the Montney region of northeastern British Columbia from a Canadian subsidiary of Murphy Oil Corporation. Together, the two plants have capacity of 320 million cubic feet per day and will serve to enhance the Company’s natural gas footprint within the Montney region, one of the most attractive natural gas plays in North America. Other projects completed within the Gas Pipelines and Processing segment included the 100,000 bpd Heidelberg Pipeline in the Gulf of Mexico and the expansion of the Aux Sable Extraction Plant in Channahon, Illinois, providing approximately 24,500 bpd of incremental fractionation capacity to this plant.

30

In keeping with the Company’s strategic priority to enhance strategic growth platforms and sustain long-term growth, Enbridge continues to expand its renewable energy generation capacity. Within the Green Power and Transmission segment, the New Creek Wind Project entered service in December 2016, increasing Enbridge’s net operating renewable power generating capacity to approximately 1,900-MW. Also in 2016, Enbridge announced the acquisition of the 249-MW Chapman Ranch Wind Project in Texas. Construction on the Company’s previously announced 24.9% interest in the 400-MW Rampion Project in the United Kingdom is also continuing, with these two projects expected to be placed into service in 2017 and 2018, respectively. In February 2017, the Company also announced it had acquired an effective 50% interest in the partnership that holds the 497-MW Hohe See Offshore Wind Project in Germany, with a targeted in-service date in 2019, increasing Enbridge’s net operating renewable power generating capacity to approximately 2,500 MW.

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 December 31, 2016.

31

				Expected
		Estimated	Expenditures	In-Service
		Capital Cost1	to Date2	Date	Status
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
1.	Eastern Access (EEP) 3	US$0.3 billion	US$0.3 billion	2016	Complete
2.	Norlite Pipeline System (the Fund	$1.3 billion	$0.8 billion	2017	Under
	Group)4				construction
3.	JACOS Hangingstone Project (the	$0.2 billion	$0.1 billion	2017	Under
	Fund Group)				construction
4.	Regional Oil Sands Optimization	$2.6 billion	$2.2 billion	2017	Under
	Project (the Fund Group)			(in phases)	construction
5.	Bakken Pipeline System (EEP)	US$1.5 billion	No significant	2017	Under
			expenditures to date		construction
6.	Lakehead System Mainline	US$0.8 billion	US$0.7 billion	2016-2019	Under
	Expansion (EEP)3			(in phases)	construction
7.	Canadian Line 3 Replacement	$4.9 billion	$1.5 billion	2019	Pre-
	Program (the Fund Group)5				construction
8.	U.S. Line 3 Replacement Program	US$2.6 billion	US$0.4 billion	2019	Pre-
	(EEP)3,5				construction
9.	Sandpiper Project (EEP)6	US$2.6 billion	US$0.8 billion	Application	Application
				withdrawn	withdrawn
GAS DISTRIBUTION
10.	Greater Toronto Area Project	$0.9 billion	$0.9 billion	2016	Complete
GAS PIPELINES AND PROCESSING
11.	Walker Ridge Gas Gathering System	US$0.4 billion	US$0.3 billion	2014-TBD	Complete
				(in phases)
12.	Big Foot Oil Pipeline	US$0.2 billion	US$0.2 billion	TBD	Complete
13.	Eaglebine Gathering (EEP)	US$0.2 billion	US$0.1 billion	2015-TBD	Complete
				(in phases)	(Phase 1)
14.	Heidelberg Oil Pipeline	US$0.1 billion	US$0.1 billion	2016	Complete
15.	Tupper Main and Tupper West Gas	$0.5 billion	$0.5 billion	2016	Acquisition
	Plants				completed
16.	Aux Sable Extraction Plant Expansion	US$0.1 billion	US$0.1 billion	2016	Complete
17.	Stampede Oil Pipeline	US$0.2 billion	US$0.1 billion	2018	Under
					construction
GREEN POWER AND TRANSMISSION
18.	New Creek Wind Project	US$0.2 billion	US$0.2 billion	2016	Complete
19.	Chapman Ranch Wind Project	US$0.4 billion	US$0.3 billion	2017	Under
					construction
20.	Rampion Offshore Wind Project	$0.8 billion	$0.4 billion	2018	Under
		(£0.37 billion)	(£0.20 billion)		construction
21.	Hohe See Offshore Wind Project7	$1.7 billion	No significant	2019	Pre-
		(€1.07 billion)	expenditures to date		construction
1	These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect Enbridge’s share of joint venture projects.
2	Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2016.
3	The Eastern Access and Lakehead System Mainline Expansion projects are funded 75% by Enbridge and 25% by EEP. As discussed under L3R Program below, following EEP’s January 27, 2017 announcement, the U.S. L3R Program is being funded 99% by Enbridge and 1% by EEP. EEP also increased its joint funding in Eastern Access by 15%.
4	Enbridge will construct and operate Norlite. Keyera Corp. will fund 30% of the project.
5	As discussed under L3R Program below, the expected cost and in-service date of this project is under review by the Company in light of the schedule for regulatory review and approval communicated by the MNPUC on October 28, 2016.
6	The Company planned to construct and operate the Sandpiper Project with MPC funding 37.5% of the project. However, on October 28, 2016, the MNPUC approved EEP’s application to withdraw the Sandpiper Projects regulatory applications without conditions.
7	In February 2017, Enbridge acquired an effective 50% interest in the Hohe See Offshore Wind Project.

Risks related to the development and completion of growth projects are described under Risk Management and Financial Instruments – General Business Risks.

32

33

LIQUIDS PIPELINES

Eastern Access (EEP)

The Eastern Access initiative included a series of Enbridge and EEP crude oil pipeline projects to provide increased access to refineries in the upper midwest United States and eastern Canada. The majority of the Canadian and United States components of the Eastern Access initiative were completed between 2013 and 2015. The remaining component of the Eastern Access initiative involved a further upsizing of EEP’s Line 6B. The Line 6B capacity expansion from Griffith, Indiana to Stockbridge, Michigan increased capacity from 500,000 bpd to 570,000 bpd and included pump station modifications at the Griffith, Niles and Mendon stations, additional modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. This expansion was placed into service in June 2016 at a total cost of approximately US$0.3 billion.

The Eastern Access projects undertaken by EEP were funded 75% by Enbridge and 25% by EEP. On January 27, 2017, EEP exercised its option to acquire an additional 15% economic interest in the Eastern Access projects at a book value of approximately US$360 million.

In July 2015, Enbridge and EEP reached an agreement to forego distributions to Enbridge Energy, Limited Partnership (EELP) for its interests in the Eastern Access projects until the second quarter of 2016. EELP holds partnership interests in assets that are jointly funded by Enbridge and EEP, including the Eastern Access projects. In return, until the second quarter of 2016, Enbridge’s capital funding contribution requirements to the Eastern Access projects were offset against its foregone cash distribution.

Norlite Pipeline System (the Fund Group)

The Company is undertaking the development of Norlite, a new industry diluent pipeline originating from Edmonton, Alberta to meet the needs of multiple producers in the Athabasca oil sands region. The scope of the project was increased to a 24-inch diameter pipeline and based on current engineering design, will provide an initial capacity of approximately 218,000 bpd of diluent, with the potential to be further expanded to approximately 465,000 bpd of capacity with the addition of pump stations. Norlite will be anchored by throughput commitments from Suncor Energy Inc., Total E&P Canada Ltd. and Teck Resources Limited (Fort Hills Partners) for production from the proposed Fort Hills Partners’ oil sands project (Fort Hills Project) and from Suncor Energy Oil Sands Limited Partnership’s (Suncor Partnership) proprietary oil sands production. Norlite will involve the construction of a new 449-kilometre (278-mile) pipeline from the Company’s Stonefell Terminal to its Cheecham Terminal with an extension to Suncor Partnership’s East Tank Farm, which is adjacent to the Company’s existing Athabasca Terminal. Under an agreement with Keyera, Norlite has the right to access certain existing capacity on Keyera’s pipelines between Edmonton, Alberta and Stonefell, Alberta and, in exchange, Keyera has elected to participate in the new pipeline infrastructure project as a 30% non-operating owner. Norlite is expected to be completed in the second quarter of 2017 at an estimated cost of approximately $1.3 billion, with expenditures to date of approximately $0.8 billion.

JACOS Hangingstone Project (the Fund Group)

The Company is undertaking the construction of facilities and it will provide transportation services to the Japan Canada Oil Sands Limited (JACOS) Hangingstone Oil Sands Project (JACOS Hangingstone). JACOS and Nexen Energy ULC, a wholly-owned subsidiary of China National Offshore Oil Corporation Limited, are partners in the project which is operated by JACOS. The Company is constructing a new 53-kilometre (33-mile), 12-inch lateral pipeline to connect the JACOS Hangingstone project site to the Company’s existing Cheecham Terminal. The project, which will provide capacity of 40,000 bpd, has been delayed at the shippers’ request and is targeted to enter service in the third quarter of 2017. The estimated cost of the project is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion.

Regional Oil Sands Optimization Project (the Fund Group)

As part of the Regional Oil Sands Optimization project, in January 2017 the Company completed the twinning of the southern section of the Athabasca Pipeline with a 36-inch diameter pipeline from Kirby Lake, Alberta to the crude oil hub at Hardisty, Alberta. The initial capacity of the Athabasca Pipeline Twin is 450,000 bpd and it can be further expanded in the future to 800,000 bpd through additional pumping horsepower.

34

The Regional Oil Sands Optimization project also involves the upsize of a 100-kilometre (60-mile) segment of the Wood Buffalo Extension between Cheecham, Alberta and Kirby Lake, Alberta from a 30-inch diameter pipeline to a 36-inch diameter pipeline, which will connect to the origin of the Athabasca Pipeline Twin at Kirby Lake, Alberta. This component of the project is now expected to be in service in December 2017 to align with the primary shipper’s production profile.

The estimated total cost of the Regional Oil Sands Optimization Project is approximately $2.6 billion, with expenditures to date of approximately $2.2 billion.

The integrated Wood Buffalo Extension and Athabasca Pipeline Twin will transport diluted bitumen from the proposed Fort Hills Project in northeastern Alberta, as well as from oil sands production from the Suncor Partnership in the Athabasca region. The Athabasca Pipeline Twin portion of the project, after being placed into service in January 2017, is also shipping blended bitumen from the Cenovus Christina Lake Steam Assisted Gravity Drainage project near the origin of the Athabasca Pipeline Twin.

Bakken Pipeline System (EEP)

In August 2016, Enbridge and EEP announced that EEP had entered into an agreement with MPC to form a new joint venture, MarEn Bakken Company LLC, which in turn has entered into an agreement to acquire a 49% equity interest in the holding company that owns 75% of the Bakken Pipeline System from an affiliate of Energy Transfer Partners, L.P. and Sunoco Logistics Partners, L.P. Under this arrangement, EEP and MPC would indirectly hold 75% and 25% interests, respectively, of the joint venture’s 49% interest in the holding company of the Bakken Pipeline System. This transaction was closed on February 15, 2017. The purchase price of EEP’s effective 27.6% interest in the Bakken Pipeline System is US$1.5 billion.

EEP will fund the US$1.5 billion acquisition through a bridge loan provided by Enbridge through one of its affiliates. The bridge loan will remain in place until a joint funding arrangement with Enbridge and its affiliates is finalized. A special committee of independent directors of the board of Enbridge Management has been established that would establish a joint funding arrangement for this investment. This arrangement, which is expected to be finalized in the second quarter of 2017, remains subject to the review of the conflicts committee of the Board of EEP’s General Partner (GP).

The Bakken Pipeline System connects the prolific Bakken formation in North Dakota to markets in eastern PADD II and the United States Gulf Coast, providing customers with access to premium markets at a competitive cost. The Bakken Pipeline System consists of the Dakota Access Pipeline and the Energy Transfer Crude Oil Pipeline projects. The Dakota Access Pipeline consists of 1,886 kilometres (1,172 miles) of 30-inch pipeline from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois. It is expected to initially deliver in excess of 470,000 bpd of crude oil and has the potential to be expanded to 570,000 bpd. The Energy Transfer Crude Oil Pipeline consists of 100 kilometres (62 miles) of new 30-inch diameter pipe, 1,104 kilometres (686 miles) of converted 30-inch diameter pipe, and 64 kilometres (40 miles) of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas.

Lakehead System Mainline Expansion (EEP)

The Lakehead System Mainline Expansion includes several projects to expand capacity of the Lakehead System mainline between its origin at the Canada/United States border, near Neche, North Dakota, and Flanagan, Illinois. These projects are in addition to expansions of the Lakehead System mainline being undertaken as part of the Eastern Access initiative and 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.

35

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 (Department), 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 (Draft SEIS), which determined that there were no significant adverse environmental impacts from the planned capacity increase. Upon closure of a public comment period on the Draft SEIS, which is currently scheduled for March 27, 2017, the Department will review all received comments and prepare a Final SEIS. The Executive Order also requires that the Department initiate 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.” Following 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. This is expected later in the year and meanwhile, a number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with any delays in obtaining this amendment.

The remaining scope of the Lakehead System Mainline Expansion includes the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois. Included therein was additional tankage of approximately US$0.4 billion which was completed on various dates between the third quarter of 2015 and the third quarter of 2016. In addition, the expansion to increase the pipeline capacity to 1,200,000 bpd requires only the addition of pumping horsepower with no pipeline construction and is expected to cost approximately US$0.4 billion. 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 U.S. L3R Program. The expenditures incurred to date are approximately US$0.7 billion.

EEP will operate the project on a cost-of-service basis. The Lakehead System Mainline Expansion is funded 75% by Enbridge and 25% by EEP. EEP has the option to increase its economic interest held by up to an additional 15% at cost. In July 2015, Enbridge and EEP reached an agreement to forego distributions to EELP for its interests in the Lakehead System Mainline Expansion until the second quarter of 2016. EELP holds partnership interests in assets that are jointly funded by Enbridge and EEP, including the Lakehead System Mainline Expansion. In return, until the second quarter of 2016, Enbridge’s capital funding contribution requirements to the Lakehead System Mainline Expansion were offset against its foregone cash distribution.

Line 3 Replacement Program

In 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. The L3R Program will support the safety and operational reliability of the mainline system, enhance 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 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 issue the Certificate of Public Convenience and Necessity (the Certificate) for the construction and operation of the pipeline and related facilities. A decision by the Federal Cabinet was expected to be issued three months following the NEB recommendation per legislation. However, because of the Federal Government’s January 27, 2016 announcement that, outside of the NEB process it had directed Federal agencies to conduct an assessment of direct and upstream GHG emissions and incremental consultation with affected communities and Indigenous peoples, the Minister of Natural Resources sought an extension of four months to the Government’s legislated decision-making time limit (to seven months in total). Regulatory 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 released the final assessment of the upstream GHG emissions, as well as reports summarizing the additional Crown Consultation with Indigenous groups and the public online survey conducted by Natural Resources Canada.

36

The report assessing the upstream GHG emissions estimates that the upstream GHG emissions in Canada associated with the production and processing of crude oil transported by the Canadian L3R Program, based on a capacity of 760,000 bpd, could be between 19 and 26 megatonnes of carbon dioxide equivalent per year. The report also found that the estimated emissions are not necessarily incremental; the degree to which the estimated emissions would be incremental depends on the expected price of oil, the availability and costs of other transportation modes, such as crude by rail, and whether other pipeline projects are built. The Crown Consultation report concluded that the NEB recommended conditions along with the commitments made by Enbridge are responsive to, and reasonably accommodate the project specific concerns raised by Indigenous groups and that other concerns will be addressed by the Government’s commitment to modernize the NEB and to review the environmental assessment legislation. The report summarizing the online survey states that 3,170 submissions were received in response to the questionnaire including from both individuals directly affected by the project, as well as general members of the public, and the report concluded that the majority of concerns centered around issues dealt with by the NEB including soil and ground water contamination and impact to farmers and nearby communities.

In December 2016, the Manitoba Metis Federation and the Association of Manitoba Chiefs applied to the Federal Court of Appeal (Federal Court) for leave to judicially review the Government of Canada’s decision to approve the Canadian L3R Program. The outcome or timing of these proceedings, including their potential impact upon the Canadian L3R Program cannot be predicted at this time.

Subject to regulatory and other approvals, the Canadian L3R Program is targeted to be completed in 2019 at an estimated capital cost of approximately $4.9 billion, with expenditures to date of approximately $1.5 billion. With a delay in construction arising from a longer than anticipated permitting process, the cost of this project is expected to increase. Also, in view of the MNPUC’s decision in respect of the schedule for the remainder of the regulatory approval process for the U.S. L3R Program, as discussed in United States Line 3 Replacement Program (EEP) below, the Company is reviewing the expected impact on the Canadian L3R Program’s schedule and cost estimates. It is possible that the in-service date could be delayed, at least until later in 2019. Costs of the Canadian L3R Program will be recovered through a 15-year toll surcharge mechanism under the CTS.

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 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 MNPUC. The MNPUC found both the Certificate of Need and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. With respect to the Route Permit, the Minnesota Department of Commerce (DOC) held public scoping meetings in August 2015.

On February 1, 2016, the MNPUC issued a written order (the U.S. L3R Order) joining the Line 3 Certificate of Need and Route Permit dockets, requiring the DOC to prepare a final Environmental Impact Statement (EIS) before Certificate of Need and Route Permit processes commence, and sent the cases to the Office of Administrative Hearings with direction to re-start the process. On February 5, 2016, EEP filed a Petition for Reconsideration of the requirement to provide a final EIS ahead of the commencement of the Certificate of Need and Route Permit proceedings noted in the U.S. L3R Order. At a hearing held on March 24, 2016, the MNPUC denied the Petition for Reconsideration.

With the issuance of the Environmental Assessment Worksheet (EAW) on April 11, 2016, the MNPUC commenced the EIS process. Consultation regarding the EAW, which defines the scope of the EIS, commenced with a series of public meetings in communities in Minnesota on April 25, 2016, which concluded on May 13, 2016. The DOC addressed the comments received on the draft EIS scope and issued its scoping recommendations to the MNPUC on September 22, 2016.

37

Three external parties filed motions requesting that the scoping process be re-opened or that a comment period be established because of the issuance of the Consent Decree settling the Line 6B pipeline crude oil release in Marshall, Michigan and the withdrawal of regulatory applications pending with the MNPUC with respect to the Sandpiper Project discussed below. EEP filed a reply challenging the need to re-open the scoping process indicating that neither of these events warrants further extension of time. The motions filed by the external parties were considered and denied by the MNPUC at a hearing held on October 28, 2016.

At the hearing on October 28, 2016, the MNPUC also approved the scope of the EIS. The MNPUC’s decision was confirmed in a written order on November 30, 2016. The DOC published the EIS Public Notice on December 5, 2016, which provided greater clarity with respect to the timeline for the regulatory approval of the U.S. L3R Program in Minnesota. On December 20, 2016, two intervenors filed petitions for reconsideration of the MNPUC’s November 30, 2016 order. EEP filed a response on January 3, 2017. The MNPUC denied the petitions at a hearing which took place on February 9, 2017. EEP is currently evaluating the impact of the MNPUC’s November 30, 2016 order on the cost and in-service date of this project. It is possible, under the schedule approved by the MNPUC, that the in-service date could be delayed, at least until later in 2019.

On January 27, 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 book value until four years after the project is placed into service.

EEP will recover the costs 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.

Sandpiper Project (EEP)

The Sandpiper Project was part of the Light Oil Market Access Program initiative and would have expanded and extended EEP’s North Dakota feeder system. The Bakken takeaway capacity of the North Dakota System would have been expanded by 225,000 bpd to a total of 580,000 bpd. The proposed expansion involved construction of a 965-kilometre (600-mile) line from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line would have twinned the existing 210,000 bpd North Dakota System mainline, which now terminates at Clearbrook Terminal in Minnesota, by adding 250,000 bpd of capacity between Tioga and Berthold, North Dakota and 225,000 bpd of capacity between Berthold and Clearbrook, both with new 24-inch diameter pipelines, as well as adding 375,000 bpd of capacity between Clearbrook and Superior with a new 30-inch diameter pipeline.

On September 1, 2016, EEP announced that it applied for the withdrawal of regulatory applications for the Sandpiper Project pending with the MNPUC because EEP concluded that the project should be delayed until such time as crude oil production in North Dakota recovers sufficiently to support development of new pipeline capacity. Based on updated projections, EEP expects that this pipeline capacity will not likely be needed until beyond its current five-year planning horizon. On October 28, 2016, the MNPUC approved EEP’s application to withdraw the regulatory applications without conditions and issued the written order on November 10, 2016.

In connection with the above announcement and other factors, EEP also evaluated the Sandpiper Project for impairment and determined that the project was impaired. In the third quarter of 2016, EEP recorded an asset impairment of US$763 million, including related project costs. Of the total amount, US$270 million was allocated to MPC, EEP’s partner in the Sandpiper Project, and US$493 million was attributable to EEP’s unitholders. The Company’s Consolidated Statements of Earnings for the year ended December 31, 2016 includes a gross charge, including additional project costs incurred in the fourth quarter, of $1,004 million, of which $875 million was attributable to noncontrolling interests in EEP and MPC and $81 million after-tax attributable to Enbridge’s common shareholders.

38

GAS DISTRIBUTION Greater Toronto Area (GTA) Project EGD undertook the expansion of its natural gas distribution system in the GTA to meet the demands of growth and to continue the safe and reliable delivery of natural gas to current and future customers. The GTA project involved the construction of two new segments of pipeline, a 27-kilometre (17-mile), 42-inch diameter pipeline (Western segment) and a 23-kilometre (14-mile), 36-inch diameter pipeline (Eastern segment) as well as related facilities to upgrade the existing distribution system that delivers natural gas to several municipalities in the GTA. Both the Western and Eastern segments were placed into service in March 2016. The total project cost was approximately $0.9 billion.

GAS PIPELINES AND PROCESSING

Walker Ridge Gas Gathering System

The Company has agreements with Chevron USA Inc. (Chevron) and several other producers, to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, the Company constructed and owns and operates the WRGGS to provide natural gas gathering services to the Chevron operated Jack St. Malo and Big Foot ultra-deep water developments. The WRGGS includes 274 kilometres (170 miles) of 8-inch or 10-inch diameter pipeline at depths of up to approximately 2,150 metres (7,000 feet), with capacity of 100 mmcf/d. The Jack St. Malo portion of the WRGGS was placed into service in December 2014. The Big Foot Gas Pipeline portion of the WRGGS has been installed on the sea floor and is awaiting Big Foot platform installation, which has been delayed due to installation problems experienced by Chevron. Chevron continues to assess the extent of the delay. Notwithstanding the Big Foot platform installation delay, the Company began collecting certain fees specified in the transportation services agreements effective the fourth quarter of 2015. The total WRGGS project is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.3 billion.

Big Foot Oil Pipeline

Under agreements with Chevron, Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc., the Company completed the installation on the sea floor of a 64-kilometre (40-mile), 20-inch oil pipeline with a capacity of 100,000 bpd from Chevron’s Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil pipeline project is complementary to the Company’s undertaking of the WRGGS construction, discussed above. Upon completion of the project, the Company will operate the Big Foot Pipeline, located approximately 274 kilometres (170 miles) south of the coast of Louisiana. As noted above, although the Big Foot ultra-deep water development has been delayed, the Company began collecting certain fees in the fourth quarter of 2015. The estimated capital cost of the project is approximately US$0.2 billion, with expenditures to date of approximately US$0.2 billion.

39

40

Eaglebine Gathering (EEP)

In 2015, EEP and MEP announced their entry into the emerging Eaglebine shale play in East Texas through two transactions totalling approximately US$0.2 billion. One of the transactions involved MEP acquiring New Gulf Resources, LLC’s midstream business in Leon, Madison and Grimes Counties, Texas. The acquisition was completed in 2015 and consisted of a natural gas gathering system that is currently in operation. In 2015, EEP and MEP also completed construction of the Ghost Chili pipeline project, which consisted of a lateral and associated facilities that created gathering capacity of over 50 mmcf/d for rich natural gas to be delivered from Eaglebine production areas to their complex of cryogenic processing facilities in East Texas. As part of Phase I, the initial facilities were placed into service in October 2015. EEP also expects to construct the Ghost Chili Extension Lateral to fully utilize the gathering capacity with the rest of EEP’s processing assets when additional development in the basin supports it. Given the proximity of EEP’s existing East Texas assets, this expansion into Eaglebine will allow EEP to offer gathering and processing services while leveraging assets on its existing footprint. Expenditures incurred to date are approximately US$0.1 billion.

Heidelberg Oil Pipeline

The Company constructed and owns and operates a crude oil pipeline in the Gulf of Mexico which connects the Heidelberg development, operated by Anadarko Petroleum Corporation, to an existing third party system. Heidelberg Pipeline, a 58-kilometre (36-mile), 20-inch diameter pipeline with capacity of 100,000 bpd, originates in Green Canyon Block 860, approximately 320 kilometres (200 miles) southwest of New Orleans, Louisiana at an estimated depth of 1,600 metres (5,300 feet). Heidelberg Pipeline was placed into service in January 2016 at an approximate cost of US$0.1 billion.

Tupper Main and Tupper West Gas Plants

In April 2016, Enbridge completed the acquisition of the Tupper Plants and associated pipelines from a Canadian subsidiary of Murphy Oil Corporation for a purchase price of approximately $0.5 billion. The Tupper Plants have a combined total licensed capacity of 320 million cubic feet per day and are located within the Montney gas play, 35 kilometres (22 miles) southwest of Dawson Creek, British Columbia, adjacent to Enbridge’s existing Sexsmith gathering system and close to the Alliance Pipeline, which is 50% owned by the Fund Group. These assets, including 53 kilometres (33 miles) of high pressure pipelines, are currently in operation and are underpinned by long-term take-or-pay contracts.

Aux Sable Extraction Plant Expansion

In September 2016, the Company completed the expansion of fractionation capacity and related facilities at the Aux Sable extraction and fractionation plant located in Channahon, Illinois. The expansion provides approximately 24,500 bpd of incremental fractionation capacity and will serve the growing NGL-rich gas stream on the Alliance Pipeline, allow for effective management of Alliance Pipeline’s downstream natural gas heat content and support additional production and sale of NGL products. The Company’s share of the project cost was approximately US$0.1 billion.

Stampede Oil Pipeline

In 2015, Enbridge announced that it will build, own and operate a crude oil pipeline in the Gulf of Mexico to connect the planned Stampede development, which is operated by Hess Corporation, to an existing third party pipeline system. The Stampede Pipeline, a 26-kilometre (16-mile), 18-inch diameter pipeline with capacity of approximately 100,000 bpd, will originate in Green Canyon Block 468, approximately 350 kilometres (220 miles) southwest of New Orleans, Louisiana, at an estimated depth of 1,200 metres (3,900 feet). Stampede Pipeline is expected to be completed at an approximate cost of US$0.2 billion and is expected to be placed into service in 2018. Expenditures incurred to date are approximately US$0.1 billion.

41

42

GREEN POWER AND TRANSMISSION

New Creek Wind Project

In 2015, Enbridge announced it had acquired a 100% interest in the 103-MW New Creek Wind Project, located in Grant County, West Virginia, from EverPower Wind Holdings, LLC. The project comprised 49 Gamesa turbines and it entered service in December 2016. The New Creek Wind Project was constructed under a fixed-price engineering, procurement and construction agreement, with White Construction Inc. at a total cost of approximately US$0.2 billion. Gamesa is providing turbine operations and maintenance services under a five-year fixed price contract. The project was backed by medium and long-term power offtake agreements, as well as renewable energy credit sales.

Chapman Ranch Wind Project

On September 9, 2016, Enbridge acquired a 100% interest in the 249-MW Chapman Ranch Wind Project, located in Nueces County, Texas, from Apex Clean Energy Holdings, LLC. Enbridge’s total investment is expected to be approximately US$0.4 billion, with expenditures incurred to date of approximately US$0.3 billion. The Chapman Ranch Wind Project will consist of 81 Acciona Windpower North America, LLC (Acciona) turbines and is expected to be in service in the third quarter of 2017. The project is being constructed under a fixed-price engineering, procurement and construction agreement, with Renewable Energy Systems America Inc. Acciona will provide 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.

Rampion Offshore Wind Project

In 2015, Enbridge announced the acquisition of a 24.9% interest in the 400-MW Rampion Project in the United Kingdom, located 13 kilometres (8 miles) off the Sussex coast in the United Kingdom at its nearest point. The Company’s total investment in the project through construction is expected to be approximately $0.8 billion (£0.37 billion). The Rampion Project was developed and is being constructed by E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE. Construction of the wind farm began in September 2015 and it is expected to be fully operational in 2018. The Rampion Project is backed by revenues from the United Kingdom’s fixed price Renewable Obligation certificates program and a 15-year PPA. Under the terms of the agreement, Enbridge became one of the three shareholders in Rampion Offshore Wind Limited which owns the Rampion Project with the United Kingdom’s Green Investment Bank plc holding a 25% interest and E.ON SE retaining the balance of 50.1% interest. Enbridge has incurred costs to date of approximately $0.4 billion (£0.20 billion).

Hohe See Offshore Wind Project

On February 17, 2017, the Company announced it had acquired an effective 50% interest in the partnership that will construct the 497-MW Hohe See Offshore Wind Project. Enbridge will partner with state-owned German utility EnBW in the construction and operation of this late-design project, with the target in-service date of 2019. The Hohe See Offshore Wind Project is located in the North Sea, 98 kilometres (61 miles) off the coast of Germany and will be constructed under fixed-price engineering, procurement, construction and installation contracts, which have been secured with key suppliers. The Hohe See Offshore Wind Project is backed by a government legislated 20-year revenue support mechanism. Enbridge’s total investment in this project through the project’s completion and in-service date in 2019 is expected to be approximately $1.7 billion (€1.07 billion), including planned spend of approximately $0.6 billion (€0.44 billion) throughout 2017.

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 additional projects under development that have not yet progressed to the point of public announcement.

LIQUIDS PIPELINES

Northern Gateway Project

Northern Gateway involved constructing a twin 1,178-kilometre (731-mile) pipeline system from near Edmonton, Alberta to a new marine terminal in Kitimat, British Columbia. One pipeline would transport crude oil for export from the Edmonton area to Kitimat and was proposed to be a 36-inch diameter line with an initial capacity of 525,000 bpd. The other pipeline would be used to transport imported condensate from Kitimat to the Edmonton area and was proposed to be a 20-inch diameter line with an initial capacity of 193,000 bpd.

43

In 2010, Northern Gateway submitted an application to the Joint Review Panel (JRP) which had a broad mandate to assess the potential environmental effects of the project and to determine if development of Northern Gateway was in the public interest.

In December 2013, the JRP issued its report on Northern Gateway. The report found that the petroleum industry is a significant driver of the Canadian economy and an important contributor to the Canadian standard of living and noted that the benefits of Northern Gateway outweigh its burdens and that “Canadians would be better off with the Enbridge Northern Gateway Project than without it.”

In June 2014, the Governor in Council (GIC) approved Northern Gateway, subject to 209 conditions. Nine applications to the Federal Court for leave for judicial review of the Order in Council approving the project were filed in July 2014. The applicants made two basic arguments in seeking leave. First, they argued that the JRP report and the Order in Council contain evidentiary gaps or gaps in reasoning. Second, they alleged that the Crown failed to discharge its constitutional duty to consult and, if appropriate, accommodate the Aboriginal applicants.

The decision of the Federal Court was released on June 30, 2016. The Federal Court found that for the most part the environmental review and Aboriginal consultation processes were reasonable, and the legal challenges to those aspects of the process were dismissed. However, the Federal Court found the Phase IV Crown consultation process undertaken by the Federal Government was unacceptably flawed, and for that reason it quashed the Certificates and sent the matter back to the GIC for redetermination.

The Federal Court indicated that the GIC had three options available on redetermination: it could redo the Phase IV Crown consultation and then direct the NEB to issue the Certificates, it could direct the NEB to dismiss the application for the Certificates, or it could ask the NEB to reconsider its recommendations.

Neither Northern Gateway nor the Federal Government sought leave to appeal to the Supreme Court of Canada.

The Federal Government chose not to re-do the Crown consultation. By way of an Order in Council dated November 25, 2016, the GIC directed the NEB to dismiss Northern Gateway’s application for the Certificates. On December 6, 2016, the NEB issued orders rescinding the Certificates, thereby effectively cancelling the project.

In consultation with the potential shippers and Aboriginal equity partners, the Company has assessed the Federal Government’s decision and concluded that Northern Gateway cannot proceed as envisioned. Project activity is limited to winding down while evaluating potential value preservation options. Total expenditures incurred to date on the project are approximately $656 million. After taking into consideration the amount recoverable from potential shippers on Northern Gateway, the Company reflected an impairment of $373 million ($272 million after-tax) in the fourth quarter of 2016 within the Liquids Pipelines segment.

GREEN POWER AND TRANSMISSION

Éolien Maritime France SAS

Effective May 19, 2016, Enbridge acquired a 50% interest in 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 holds licenses for three large-scale offshore wind farms off the coast of France that would produce a combined 1,428 MW of power. The development of these projects is subject to 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 $194 million (€136 million).

44

LIQUIDS PIPELINES

EARNINGS BEFORE INTEREST AND INCOME TAXES

	2016		2015		2014
(millions of Canadian dollars)
Canadian Mainline	931		896		663
Lakehead System	1,425		1,108		836
Regional Oil Sands System	384		341		301
Mid-Continent and Gulf Coast	656		516		319
Southern Lights Pipeline	168		155		121
Bakken System	198		213		233
Feeder Pipelines and Other	196		155		119
Adjusted earnings before interest and income taxes	3,958		3,384		2,592
Canadian Mainline - changes in unrealized derivative fair value gains/(loss)	467		(1,390	)	(499	)
Canadian Mainline - Line 9B costs incurred during reversal	-		(3	)	(5	)
Lakehead System - changes in unrealized derivative fair value gains/(loss)	(6	)	(10	)	8
Lakehead System - hydrostatic testing	15		(72	)	-
Lakehead System - leak remediation costs, net of leak insurance recovery	3		-		(97	)
Regional Oil Sands System - northeastern Alberta wildfires pipelines and facilities restart costs	(47	)	-		-
Regional Oil Sands System - make-up rights adjustment	(32	)	9		8
Regional Oil Sands System - leak remediation and long- term pipeline stabilization costs, net of leak insurance recoveries	5		26		5
Regional Oil Sands System - loss on disposal of non-core assets	-		(9	)	-
Regional Oil Sands System - prior period adjustment	-		21		-
Mid-Continent and Gulf Coast - changes in unrealized derivative fair value gains/(loss)	(2	)	(7	)	4
Mid-Continent and Gulf Coast - make-up rights adjustment	(97	)	(54	)	(41	)
Southern Lights Pipeline - changes in unrealized derivative fair value gains/(loss)	19		(87	)	3
Bakken System - Sandpiper asset impairment	(1,004	)	-		-
Bakken System - asset impairment	-		(86	)	-
Bakken System - changes in unrealized derivative fair value gains/(loss)	(4	)	(5	)	4
Bakken System - make-up rights adjustment	2		8		(3	)
Feeder Pipelines and Other - gain on sale of South Prairie Region assets	850		-		-
Feeder Pipelines and Other - Northern Gateway asset impairment loss	(373	)	-		-
Feeder Pipelines and Other - Eddystone Rail impairment loss	(184	)	-		-
Feeder Pipelines and Other - gain on sale of non-core assets	-		91		-
Feeder Pipelines and Other - derecognition of regulatory balances	(6	)	-		-
Feeder Pipelines and Other - make-up rights adjustment	(2	)	(6	)	5
Feeder Pipelines and Other - project development costs	(5	)	(3	)	(4	)
Feeder Pipelines and Other - changes in unrealized derivative fair value loss	-		(1	)	-
Earnings before interest and income taxes	3,557		1,806		1,980

45

Liquids Pipelines adjusted EBIT was $3,958 million in 2016 compared with adjusted EBIT of $3,384 million in 2015 and $2,592 million in 2014. The Company continued to realize growth on the Canadian Mainline, Lakehead System and Regional Oil Sands System primarily due to higher throughput that resulted from strong oil sands production in western Canada enabled by pipeline capacity expansion projects placed into service in 2015 and 2014. However, the positive effect of increased capacity on liquids pipelines throughput was substantially negated in the second quarter by the impact of extreme wildfires in northeastern Alberta which led to a temporary shutdown of certain of the Company’s upstream pipelines and terminal facilities resulting in a disruption of service on Enbridge’s Regional Oil Sands System with corresponding impacts on Enbridge’s downstream pipelines deliveries, including Canadian Mainline and the Lakehead System. Growth in Canadian Mainline adjusted EBIT was also affected by a combination of a lower average IJT Residual Benchmark Toll, which decreased effective April 1, 2016, and a lower foreign exchange rate on hedges used to convert United States dollar denominated toll revenue on the Canadian Mainline in 2016. The Lakehead System delivered strong operating performance driven by higher Lakehead System Local Toll, higher throughput and contributions from new assets placed into service in 2015. In 2016, the Company also benefitted from stronger adjusted EBIT contributions from the United States Mid-Continent and Gulf Coast systems, attributable to increased transportation revenues mainly resulting from an increase in the level of committed take-or-pay volumes on Flanagan South.

Additional details on items impacting Liquids Pipelines EBIT include:

·Canadian Mainline EBIT for each year reflected changes in unrealized fair value gains and losses on derivative financial instruments used to manage risk exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices.

·Canadian Mainline EBIT for 2015 and 2014 included depreciation expense charged to Line 9B while it was idled and undergoing a reversal as part of the Company’s Eastern Access initiative.

·Lakehead System EBIT for 2016 included recoveries, as well as charges in 2015, in relation to hydrostatic testing performed on Line 2B in 2015.

·Lakehead System EBIT for 2016 and 2014 included charges related to estimated costs, before insurance recoveries, associated with the Line 6B crude oil release, as well as insurance recoveries associated with the Line 6A crude oil release.

·Regional Oil Sands System EBIT for each year included make-up rights adjustments. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. Generally, under such take-or-pay contracts, payments are received rateably over the life of the contract as capacity is provided, regardless of volumes shipped, and are non-refundable. Should make-up rights be utilized in future periods, costs associated with such transportation service are typically passed through to shippers, such that little or no cost is borne by Enbridge. For the purposes of adjusted EBIT, the Company reflects contributions from these contracts rateably over the life of the contract, consistent with contractual cash payments under the contract.

·Regional Oil Sands System EBIT for each year included insurance recoveries, as well as charges in 2015 and 2014, associated with the Line 37 crude oil release which occurred in June 2013. Refer to Liquids Pipelines – Regional Oil Sands System – Line 37 Crude Oil Release.

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

·Bakken System loss before interest and income taxes for 2016 reflected impairment charges, 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. For additional information, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Sandpiper Project (EEP).

·Bakken System EBIT for 2015 reflected an asset impairment charge related to EEP’s Berthold rail facility due to contracts that have not been renewed beyond 2016.

·Feeder Pipelines and Other EBIT for 2016 reflected a gain on the sale of non-core South Prairie Region assets.

·Feeder Pipelines and Other EBIT for 2016 included an asset impairment charge related to Northern Gateway. For additional information, refer to Other Announced Projects Under Development – Liquids Pipelines – Northern Gateway Project.

46

·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 which impacted volumes at the rail facility.

·Feeder Pipelines and Other EBIT for each year included certain business development costs related to Northern Gateway.

IMPACT OF WILDFIRES IN NORTHEASTERN ALBERTA

During the first week of May 2016, extreme wildfires in northeastern Alberta resulted in the shutdown of a number of oil sands production facilities and the evacuation of more than 80,000 people from the city of Fort McMurray, which serves as a commercial and regional logistics centre for the oil sands region and a home to a significant portion of the oil sands workforce.

Enbridge’s facilities in the region were largely unaffected; however, as a precautionary measure on May 4, 2016, the Company temporarily shut down and evacuated its Cheecham terminal and curtailed operations at its Athabasca terminal. The Company also isolated and shut down pipelines in and out of the Cheecham terminal and shut down or curtailed operations on other pipelines it operates in the region.

The Company coordinated with emergency response, public safety and utility officials to restore power and make any necessary repairs to its systems while working closely with producers in the region, and restarted and returned the majority of its regional pipeline systems to normal operation by the end of May 2016.

Oil sands production from facilities in the vicinity of Fort McMurray, Alberta was curtailed longer given the severity and longevity of the wildfires, with oil sands production substantially coming back online by the end of June 2016. On average, Enbridge’s mainline system deliveries were lower by approximately 255,000 bpd during the months of May and June 2016, which represented an approximate 10% decrease in throughput compared with the throughput that the Company was delivering prior to the wildfires. In the third quarter of 2016, throughput on the Company’s mainline system and overall system utilization strengthened. As a result, the negative impact of reduced system deliveries on revenues impacting the Company’s adjusted EBIT and ACFFO for the second half of 2016 remained unchanged since the end of the second quarter of 2016 at approximately $74 million. The Company’s adjusted earnings and adjusted earnings per share for the year ended December 31, 2016 were reduced by $26 million and $0.03, respectively.

CANADIAN MAINLINE

The mainline system is comprised of the Canadian Mainline and the Lakehead System. The Canadian Mainline is a common carrier pipeline system which transports various grades of oil and other liquid hydrocarbons within western Canada and from western Canada to the Canada/United States border near Gretna, Manitoba and Neche, North Dakota and from the United States/Canada border near Port Huron, Michigan and Sarnia, Ontario to eastern Canada and the northeastern United States. The Canadian Mainline includes six adjacent pipelines, with a combined design operating capacity of approximately 2.85 million bpd that connect with the Lakehead System at the Canada/United States border, as well as four crude oil pipelines and one refined products pipeline that deliver into eastern Canada and the northeastern United States. It also includes certain related pipelines and infrastructure, including decommissioned and deactivated pipelines. Enbridge has operated, and frequently expanded, the Canadian Mainline since 1949. Effective September 1, 2015, the closing date of the Canadian Restructuring Plan, Enbridge transferred the Canadian Mainline to the Fund Group – see Canadian Restructuring Plan. The Lakehead System is the portion of the mainline system in the United States that continues to be managed by Enbridge through its subsidiaries, EEP and EELP – see Liquids Pipelines – Lakehead System.

47

Competitive Toll Settlement

The CTS is the current framework governing tolls paid for products shipped on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis. The 10-year settlement was negotiated by representatives of Enbridge, the Canadian Association of Petroleum Producers and shippers on the Canadian Mainline. It was approved by the NEB on June 24, 2011 and took effect on July 1, 2011. The CTS provides for a Canadian Local Toll (CLT) for deliveries within western Canada, which is based on the 2011 Incentive Tolling Settlement toll, as well as an IJT for crude oil shipments originating in western Canada on the Canadian Mainline and delivered into the United States, via the Lakehead System, and into eastern Canada. These tolls are denominated in United States dollars. The IJT is designed to provide shippers on the mainline system with a stable and competitive long-term toll, thereby preserving and enhancing throughput on both the Canadian Mainline and the Lakehead System. The IJT and the CLT were both established at the time of implementation of the CTS and are adjusted annually, on July 1 of each year, at a rate equal to 75% of the Canada Gross Domestic Product at Market Price Index published by Statistics Canada. Certain events may trigger a renegotiation of the CTS by Enbridge or the shippers. These include (i) a regulatory change that results in cumulative capital expenditures for integrity work on the Canadian Mainline increasing by more than $100 million, or (ii) if the nine month average volume on the Canadian Mainline, ex-Gretna, Manitoba, falls below the minimum threshold volume (currently 1.35 million bpd). If a renegotiation of the CTS is triggered, Enbridge and the shippers will meet and use reasonable efforts to agree on how the CTS can be amended to accommodate the event. If Enbridge and the shippers are unable to agree on the manner in which the CTS is to be amended, then, absent an extension to the renegotiation period, the CTS will terminate and Enbridge will need to file a new toll application for the Canadian Mainline. Two years prior to the end of the term of the CTS, Enbridge and the shippers will establish a group for the purposes of negotiating a new settlement to replace the CTS once it expires.

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

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

Results of Operations

Canadian Mainline adjusted EBIT was $931 million for the year ended December 31, 2016 compared with $896 million for the year ended December 31, 2015. The year-over-year increase reflected higher throughput driven by strong oil sands production combined with contributions from new assets placed into service in 2015, the most prominent being the expansion of the Company’s mainline system completed in the third quarter of 2015 and the reversal and expansion of Line 9B completed in the fourth quarter of 2015, as well as new surcharges for certain system expansions, including the Edmonton to Hardisty Expansion that was completed in the second quarter of 2015. Higher throughput on the Canadian Mainline also reflected increased downstream demand throughout 2016 from the completion of the Southern Access Extension in the fourth quarter of 2015. Adjusted EBIT from Southern Access Extension is reported within Feeder Pipelines and Other. Higher terminalling revenues also contributed to an increase in adjusted EBIT for the year ended December 31, 2016.

The positive effect of increased capacity on Canadian Mainline throughput discussed above was partially offset in the second quarter of 2016 by the impact of extreme wildfires in northeastern Alberta. The wildfires resulted in a curtailment of production from oil sands facilities and certain of the Company’s upstream pipelines and terminal facilities were temporarily shut down resulting in a disruption of service on Enbridge’s Regional Oil Sands System with corresponding impacts on deliveries to Enbridge’s downstream pipelines, including the Canadian Mainline. In the third quarter of 2016, throughput on the Company’s mainline system and overall system utilization strengthened. The impact of the wildfires for the year ended December 31, 2016 on Canadian Mainline adjusted EBIT has remained unchanged since the end of the second quarter of 2016 at approximately $30 million. For further details on the wildfires, refer to Liquids Pipelines – Impact of Wildfires in Northeastern Alberta.

48

Year-over-year growth in Canadian Mainline adjusted EBIT was also affected by a lower average Canadian Mainline IJT Residual Benchmark Toll. Effective April 1, 2016, Canadian Mainline IJT Residual Benchmark Toll decreased from US$1.63 to US$1.46, which more than offset the effects of the higher toll charged during the first quarter of 2016. Effective July 1, 2016, Canadian Mainline IJT Residual Benchmark Toll increased slightly to US$1.47. Changes in the Canadian Mainline IJT Residual Benchmark Toll are inversely related to the Lakehead System Toll, which was higher in 2016 due to the recovery of incremental costs associated with EEP’s growth projects.

In addition, Canadian Mainline adjusted EBIT reflected the impact of a lower period-over-period exchange rate used to record the Canadian Mainline revenues. The IJT Benchmark Toll and its components are set in United States dollars and the majority of the Company’s foreign exchange risk on Canadian Mainline revenue is hedged. For the year ended December 31, 2016, the effective hedged rate for the translation of Canadian Mainline United States dollar transactional revenues was $1.07 compared with $1.10 for the corresponding 2015 period.

In addition to the factors noted above, which partially offset the increase in Canadian Mainline adjusted EBIT for the year ended December 31, 2016, higher power costs associated with higher throughput and higher operating and administrative expense to support increased business activities also partially offset the increase.

The decrease in Canadian Mainline IJT Residual Benchmark Toll and lower foreign exchange hedge rate also resulted in a decrease in Canadian Mainline adjusted EBIT for the fourth quarter of 2016 compared with the fourth quarter of 2015.

In 2015, the Company commenced collecting, in its tolls, NEB mandated future abandonment costs from shippers. Approximately $45 million in revenues were recorded for the year ended December 31, 2016 (2015 - $38 million), but these amounts were offset by a corresponding increase in operating and administrative expense in the respective periods. For further details, refer to Critical Accounting Estimates.

Canadian Mainline adjusted EBIT was $896 million for the year ended December 31, 2015 compared with $663 million for the year ended December 31, 2014. The year-over-year increase reflected higher throughput from strong oil sands production combined with strong refinery demand in the midwest market partly due to a start-up of a midwest refinery’s conversion to heavy oil processing in the second quarter of 2014. Higher throughput in the second half of 2015 was also achieved from the expansion of the Company’s mainline system completed in July 2015 and through continued efforts by the Company to optimize capacity utilization and to enhance scheduling efficiency with shippers. Although throughput increased relative to the comparative periods in 2014, further throughput growth in 2015 was hindered by upstream plant maintenance in Alberta during the second and third quarters which impacted light volumes, and an unplanned shutdown of a midwest refinery that impacted the takeaway of heavy volumes in the third quarter. These negative impacts on throughput were alleviated towards the latter part of the fourth quarter of 2015. Other factors contributing to an increase in adjusted EBIT were higher terminalling revenues and the impact of a higher rate on hedges used to convert United States dollar denominated revenue. For the year ended December 31, 2015, the effective hedged rate for the translation of Canadian Mainline United States dollar transactional revenues was $1.10, compared with $1.02 for the corresponding 2014 period. In addition, Canadian Mainline fourth quarter of 2015 adjusted EBIT also reflected one month of revenues from Line 9B which was placed into service in December 2015.

Partially offsetting the positive factors noted above was a lower year-over-year average Canadian Mainline IJT Residual Benchmark Toll, although this impact lessened commencing the second quarter of 2015 as effective April 1, 2015, this toll increased by US$0.10 per barrel to US$1.63 per barrel. Also mitigating the impact of a lower Canadian Mainline IJT Residual Benchmark Toll were new surcharges for certain system expansions as noted above. Other factors which negatively impacted adjusted EBIT were higher power costs associated with higher throughput and higher depreciation expense due to an increased asset base.

49

Supplemental information on Canadian Mainline adjusted earnings for the years ended December 31, 2016, 2015 and 2014 is provided below.

December 31,		2016	2015	2014
(United States dollars per barrel)
IJT Benchmark Toll1		$4.05	$4.07	$4.02
Lakehead System Local Toll2		$2.58	$2.44	$2.49
Canadian Mainline IJT Residual Benchmark Toll3		$1.47	$1.63	$1.53
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, 2014, the IJT Benchmark Toll increased from US$3.98 to US$4.02 and increased to US$4.07 effective July 1, 2015. Effective July 1, 2016, this toll decreased to US$4.05.
2	The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. In 2014, EEP delayed its annual April 1 tariff filing for its Lakehead System as it was in negotiations with the Canadian Association of Petroleum Producers concerning certain components of the tariff rate structure. The toll application was filed with the Federal Energy Regulatory Commission (FERC) on June 27, 2014, and effective August 1, 2014, the Lakehead System Local Toll increased from US$2.17 to US$2.49. 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.
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 July 1, 2014, this toll increased from US$1.81 to US$1.85 and subsequently decreased to US$1.53 effective August 1, 2014, coinciding with the revised Lakehead System Local Toll. Effective April 1, 2015, the Canadian Mainline IJT Residual Benchmark Toll increased 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.

Throughput Volume1

		Q1	Q2	Q3	Q4	Full Year
(thousands of bpd)
2016		2,543	2,242	2,353	2,481	2,405
2015		2,210	2,073	2,212	2,243	2,185
2014		1,904	1,968	2,039	2,066	1,995
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.

Canadian Mainline revenues include the portion of the system covered by the CTS as well as revenues from Lines 8 and 9 in eastern Canada. Lines 8 and 9 are currently tolled on a separate basis and comprise a relatively small proportion of total Canadian Mainline revenues. Line 9B was idled during 2014 for reversal and expansion. The project was completed and the 300,000 bpd line was placed into service in December 2015. CTS revenues include transportation revenues, the largest component, as well as allowance oil and revenues from receipt and delivery charges. Transportation revenues include revenues for volumes delivered off of the Canadian Mainline at Gretna, Manitoba and on to the Lakehead System, to which Canadian Mainline IJT residual tolls apply, and revenues for volumes delivered to other western Canada delivery points, to which the CLT applies. Despite the many factors that affect Canadian Mainline revenues, the primary determinants of those revenues will be throughput volume ex-Gretna, the United States dollar Canadian Mainline IJT Residual Benchmark Toll and the effective foreign exchange rate at which resultant revenues are converted into Canadian dollars. The Company currently utilizes derivative financial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues. The exact relationship between the primary determinants and actual Canadian Mainline revenues will vary somewhat from quarter to quarter but is expected to be relatively stable on average for a year, absent a systematic shift in receipt and delivery point mix or in crude oil type mix.

The largest components of operating and administrative expense are employee related costs, pipeline integrity, repairs and maintenance, rents and leases and property taxes. Operating and administrative costs are relatively insensitive to throughput volumes.

Power, the most significant variable operating cost, is subject to variations in operating conditions, including system configuration, pumping patterns and pressure requirements; however, the primary determinants of this cost are the power prices in various jurisdictions and throughput volume. The relationship of power consumption to throughput volume is expected to be roughly proportional over a moderate range of volumes. The Company currently utilizes derivative financial instruments to hedge power prices.

50

Depreciation and amortization expense will adjust over time as a result of additions to property, plant and equipment due to new facilities, including integrity capital expenditures.

LAKEHEAD SYSTEM

The Lakehead System consists of the United States portion of the mainline system that is managed by Enbridge through its subsidiaries, EEP and EELP. For an overview of the mainline system, refer to Liquids Pipelines – Canadian Mainline.

Tariffs and Transportation Rates

Transportation rates are governed by the FERC for deliveries from the Canada-United States border near Neche, North Dakota and from Clearbrook, Minnesota to certain principal delivery points. The Lakehead System periodically adjusts these transportation rates as allowed under the FERC’s index methodology and tariff agreements, the main components of which are base rates and Facilities Surcharge Mechanism. Base rates, the base portion of the transportation rates for the Lakehead System, are subject to an annual adjustment which cannot exceed established ceiling rates as approved by the FERC. The Facilities Surcharge Mechanism allows the Lakehead System to recover costs associated with certain shipper-requested projects through an incremental surcharge in addition to the existing base rates, and is subject to annual adjustment.

Throughput Volume1

		Q1	Q2	Q3	Q4	Full Year
(thousands of bpd)
2016		2,735	2,440	2,495	2,624	2,574
2015		2,330	2,208	2,338	2,388	2,315
2014		2,000	2,088	2,172	2,187	2,113
1	Average throughput volume represents mainline system deliveries to the United States midwest and eastern Canada.

Results of Operations

Lakehead System adjusted EBIT was $1,425 million for the year ended December 31, 2016 compared with $1,108 million for the year ended December 31, 2015. The year-over-year increase in adjusted EBIT reflected stronger operating performance, as well as the favourable effect of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2016 compared with 2015.

Excluding the impact of foreign exchange translation to Canadian dollars, Lakehead System adjusted EBIT was US$1,074 million for the year ended December 31, 2016 compared with US$868 million for the year ended December 31, 2015. The year-over-year increase reflected higher Lakehead System Local Toll and higher throughput, as well as contributions from new assets placed into service in 2015, the most prominent being the expansion of the Company’s mainline system completed in the third quarter of 2015. As discussed under Canadian Mainline above, higher throughput on the Lakehead System in 2016 also reflected increased downstream demand resulting from the completion of Southern Access Extension and the reversal and expansion of Line 9B. However, deliveries to the Lakehead System from the Canadian Mainline were lower during the second quarter of 2016, as a result of the northeastern Alberta wildfires. The negative impact of the wildfires for the year ended December 31, 2016 on Lakehead System adjusted EBIT has remained unchanged since the end of the second quarter of 2016 at approximately $38 million. Also partially offsetting the year-over-year increase in adjusted EBIT were higher operating and administrative costs and higher depreciation expense from an increased asset base. Adjusted EBIT for the year ended December 31, 2016 also reflected higher power costs associated with higher throughput.

As noted above, positively impacting Lakehead System adjusted EBIT for the year ended December 31, 2016 was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in 2016. The Average Exchange Rate was $1.32 for the year ended December 31, 2016 compared with $1.28 in the corresponding 2015 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, and realized gains and losses from these derivative instruments are reported within Eliminations and Other. For further details refer to Eliminations and Other.

51

Lakehead System adjusted EBIT was $1,108 million for the year ended December 31, 2015 compared with $836 million for the year ended December 31, 2014 .The year-over-year increase in adjusted EBIT reflected stronger operating performance, as well as the favourable effect of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2015 compared with 2014.

Excluding the impact of foreign exchange translation to Canadian dollars, Lakehead System adjusted EBIT was US$868 million for the year ended December 31, 2015 compared with US$756 million for the year ended December 31, 2014. The year-over-year increase reflected higher throughput and tolls, as well as contributions from new assets placed into service in 2015 and 2014, the most prominent being the expansion of the Company’s mainline system completed in July 2015 and the replacement and expansion of Line 6B completed in 2014. Partially offsetting the increase in adjusted EBIT were higher operating and administrative costs, incremental power costs associated with higher throughput and higher depreciation expense from an increased asset base.

As noted above, positively impacting year-over-year adjusted EBIT was the favourable impact of translating United States dollar earnings at a higher Average Exchange Rate in 2015. The Average Exchange Rate was $1.28 for the year ended December 31, 2015 compared with $1.10 for the comparative period of 2014. As noted above, a portion of Lakehead System United States dollar EBIT was hedged as part of the Company’s enterprise-wide financial risk management program. For further details refer to Eliminations and Other.

Lakehead System – Alberta Clipper Drop Down

On January 2, 2015, Enbridge completed the transfer of its 66.7% interest in the United States segment of the Alberta Clipper Pipeline, held through a wholly-owned Enbridge subsidiary in the United States, to EEP. At the time of the transfer, EEP already owned the remaining 33.3% interest in the United States segment of Alberta Clipper. Aggregate consideration for the transfer was US$1 billion, consisting of approximately US$694 million of Class E equity units issued to Enbridge by EEP and the repayment of approximately US$306 million of indebtedness owed to Enbridge. The terms of the transfer were reviewed and recommended by an independent committee of EEP.

The Class E units issued to Enbridge are entitled to the same distributions as the Class A common units held by the public and are convertible into Class A common units on a one-for-one basis at Enbridge’s option. However, the Class E units were not entitled to distributions with respect to the quarter ended December 31, 2014. The Class E units are redeemable at EEP’s option after 30 years, if not converted earlier by Enbridge. The Class E units have a liquidation preference equal to their notional value at December 23, 2014 of US$38.31 per unit, which was determined based on the trailing five-day volume-weighted average price of EEP’s Class A common units.

The aggregate consideration of US$1 billion corresponded to an approximate 10.7 times multiple of then expected 2015 Alberta Clipper earnings before interest, tax, depreciation and amortization (EBITDA). The cumulative adjusted EBITDA of the Alberta Clipper Pipeline for fiscal years 2015 and 2016 exceeded the minimum required threshold set under the agreement.

The United States segment of the Alberta Clipper Pipeline is a 523-kilometre (325-mile), 36-inch diameter crude oil pipeline from the United States border near Neche, North Dakota to Superior, Wisconsin. The line had an initial capacity of 450,000 bpd and was constructed under the terms of a joint funding agreement under which Enbridge funded two-thirds of the capital costs in return for a corresponding economic interest in the earnings and cash flow from the investment. In 2015, the line was expanded in two phases to a capacity of 800,000 bpd through the addition of increased pumping horsepower; however, EEP is awaiting an amendment to the current Presidential border crossing permit to allow for operation of Alberta Clipper Pipeline at its currently planned operating capacity of 800,000 bpd. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with any delays in obtaining this amendment. The required expansion investments are subject to separate joint funding arrangements between Enbridge and EEP and were not included as part of the above noted drop down transaction. Refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Lakehead System Mainline Expansion (EEP).

52

Lakehead System Lines 6A and 6B Crude Oil Releases

Line 6B Crude Oil Release

On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Kalamazoo River via Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 61 kilometres (38 miles) of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan.

EEP continues to evaluate the need for additional remediation activities and is performing the necessary restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives EEP is undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

In May 2015, EEP reached a settlement with the Michigan Department of Environmental Quality and the Michigan Attorney General’s offices regarding the Line 6B crude oil release. As stipulated in the settlement, EEP agrees to: (1) provide at least 300 acres of wetland through restoration, creation, or banked wetland credits, to remain as wetland in perpetuity; (2) pay US$5 million as mitigation for impacts to the banks, bottomlands, and flow of Talmadge Creek and the Kalamazoo River for the purpose of enhancing the Kalamazoo River watershed and restoring stream flows in the River; (3) continue to reimburse the State of Michigan for costs arising from oversight of EEP activities since the release; and (4) continue monitoring, restoration and invasive species control within state-regulated wetlands affected by the release and associated response activities. The timing of these activities is based upon the work plans approved by the State of Michigan.

As at December 31, 2016, EEP’s total cost estimate for the Line 6B crude oil release remains at US$1.2 billion ($195 million after-tax attributable to Enbridge) since December 31, 2015. This includes a reduction of estimated remediation efforts offset by an increase in civil penalties under the Clean Water Act of the United States, as described below under Legal and Regulatory Proceedings. In addition, in the fourth quarter of 2016, the cost accruals were reduced by US$8 million ($1 million after-tax attributable to Enbridge), mainly due to optimization of EEP’s remedial investigation reporting and savings related to EEP’s residual oil monitoring and maintenance.

Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at December 31, 2016. Despite the efforts EEP has made to ensure the reasonableness of its estimates, there continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies.

Line 6A Crude Oil Release

A release of crude oil from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. EEP estimates that approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Some of the released crude oil went onto a roadway, into a storm sewer, a waste water treatment facility and then into a nearby retention pond. All but a small amount of the crude oil was recovered. EEP completed excavation and replacement of the pipeline segment and returned it to service on September 17, 2010.

EEP has completed the cleanup, remediation and restoration of the areas affected by the release. In October 2013, the National Transportation Safety Board publicly posted their final report related to the Line 6A crude oil release which states the probable cause of the crude oil release was erosion caused by a leaking water pipe resulting from an improperly installed third-party water service line below EEP’s oil pipeline.

53

The total estimated cost for the Line 6A crude oil release was approximately US$53 million ($7 million after-tax attributable to Enbridge) before insurance recoveries and including fines and penalties. These costs included emergency response, environmental remediation and cleanup activities with the crude oil release. As at December 31, 2016, EEP has no remaining estimated liability.

Insurance

EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. On May 1 of each year, the commercial liability insurance program is renewed and includes coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents excluding costs for fines and penalties.

Enbridge has renewed its comprehensive property and liability insurance programs with a liability program aggregate limit of US$900 million, which includes sudden and accidental pollution liability. The insurance programs are effective May 1, 2016 through April 30, 2017. In the unlikely event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among Enbridge entities on an equitable basis based on an insurance allocation agreement among Enbridge and its subsidiaries.

A majority of the costs incurred in connection with the crude oil release for Line 6B, other than fines and penalties, are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability for Enbridge and its affiliates. Including EEP’s remediation spending through December 31, 2016, costs related to Line 6B exceeded the limits of the coverage available under this insurance policy. Additionally, fines and penalties would not be covered under prior or existing insurance policy. As at December 31, 2016, EEP has recorded total insurance recoveries of US$547 million ($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million aggregate limit. EEP will record receivables for additional amounts it claims for recovery pursuant to its insurance policies during the period it deems recovery to be probable.

In March 2013, EEP and Enbridge filed a lawsuit against the insurers of US$145 million of coverage, as one particular insurer is disputing the recovery eligibility for costs related to EEP’s claim on the Line 6B crude oil release and the other remaining insurers asserted that their payment is predicated on the outcome of the recovery from that insurer. EEP received a partial recovery payment of US$42 million from the other remaining insurers and amended its lawsuit such that it includes only one insurer.

Of the remaining US$103 million coverage limit, US$85 million was the subject matter of a lawsuit against one particular insurer. In March 2015, Enbridge reached an agreement with that insurer to submit the US$85 million claim to binding arbitration. The recovery of the remaining US$18 million is awaiting resolution of that arbitration. While EEP believes that those costs are eligible for recovery, there can be no assurance that EEP will prevail.

In addition, and separate from the ongoing Line 6B claim, during the year ended December 31, 2016, EEP recorded an insurance recovery of US$10 million ($1 million after-tax attributable to Enbridge) associated with the Line 6A Romeoville crude oil release. This is the total insurance recovery available for the Line 6A incident.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Two actions or claims are pending against Enbridge, EEP or their affiliates in United States state courts in connection with the Line 6B crude oil release. Based on the current status of these cases, the Company does not expect the outcome of these actions to be material to its results of operations or financial condition.

Line 6A and 6B Fines and Penalties

As at December 31, 2016, included in EEP’s total estimated costs related to the Line 6B crude oil release were US$69 million in fines and penalties. Of this amount, US$61 million relates to civil penalties under the Clean Water Act of the United States, which EEP fully accrued but has not paid, pending approval of the Consent Decree, as described below.

54

In June 2015, Enbridge reached a separate agreement with the United States (Federal Natural Resources Damages Trustees), State of Michigan (State Natural Resources Damages Trustees), Match-E-Be-Nash-She-Wish Band of the Potawatomi Indians, and the Nottawaseppi Huron Band of the Potawatomi Indians, and paid approximately US$4 million that was accrued to cover a variety of projects, including the restoration of 175 acres of oak savanna in the Fort Custer State Recreation Area and wild rice beds along the Kalamazoo River.

One claim related to the Line 6A crude oil release had been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court in connection with this crude oil release. On February 20, 2015, EEP agreed to a consent order releasing it from any claims, liability, or penalties.

Consent Decree

On July 20, 2016, a Consent Decree was filed with the Western District of Michigan Southern Division (the Court). The Consent Decree is EEP’s signed settlement agreement with the Environmental Protection Agency (EPA) and the United States Department of Justice regarding Lines 6A and 6B crude oil releases. Pursuant to the Consent Decree, EEP will pay US$62 million in civil penalties: US$61 million in respect of Line 6B and US$1 million in respect of Line 6A. The Consent Decree will take effect upon approval by the Court.

In addition to the monetary fines and penalties discussed above, the Consent Decree calls for replacement of Line 3, which EEP initiated in 2014 and is currently under regulatory review in the State of Minnesota as described in Growth Projects – Commercially Secured Projects – Liquids Pipelines – Line 3 Replacement Program – United States Line 3 Replacement Program (EEP). The Consent Decree contains a variety of injunctive measures, including, but not limited to, enhancements to EEP’s comprehensive in-line inspection-based spill prevention program; enhanced measures to protect the Straits of Mackinac; improved leak detection requirements; installation of new valves to control product loss in the event of an incident; continued enhancement of control room operations; and improved spill response capabilities. Collectively, these measures build on continuous improvements implemented since 2010 to EEP’s leak detection program, control centre operations and emergency response program. EEP estimates the total cost of these measures to be approximately US$110 million, most of which is already incorporated into existing long-term capital investment and operational expense planning and guidance. Compliance with the terms of the Consent Decree is not expected to materially impact the overall financial performance of EEP or the Company.

REGIONAL OIL SANDS SYSTEM

The Regional Oil Sands System includes three intra-Alberta long haul pipelines, the Athabasca Pipeline, Waupisoo Pipeline and Woodland Pipeline and two large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta and the Cheecham Terminal, located south of Fort McMurray. The Regional Oil Sands System also includes the Wood Buffalo Pipeline and Norealis Pipeline, each of which provides access for oil sands production from north of Fort McMurray to the Cheecham Terminal. There are also other facilities such as the MacKay River, Christina Lake, Surmont, Long Lake and AOC laterals and related facilities. Regional Oil Sands System currently serves nine producing oil sands projects. Effective September 1, 2015, the closing date of the Canadian Restructuring Plan, Enbridge transferred the Regional Oil Sands System to the Fund Group - see Canadian Restructuring Plan.

The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic and heavy oil pipeline. Built in 1999, it links the Athabasca oil sands in the Fort McMurray region to the major Alberta pipeline hub at Hardisty, Alberta. The Athabasca Pipeline’s capacity is 570,000 bpd, depending on crude slate. The Company has long-term take-or-pay and non take-or-pay agreements with multiple shippers on the Athabasca Pipeline. Revenues are recorded based on the contract terms negotiated with the major shippers, rather than the cash tolls collected. In January 2017, the Company also completed the twinning of the southern section of the Athabasca Pipeline with a 36-inch diameter pipeline from Kirby Lake, Alberta to its Hardisty crude oil hub, as discussed under Growth Projects – Commercially Secured Projects – Liquids Pipelines – Regional Oil Sands Optimization Project (the Fund Group).

The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered service in 2008 and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline originates at the Cheecham Terminal and terminates at the major Alberta pipeline hub at Edmonton. The pipeline has a capacity of 550,000 bpd, depending on crude slate. The Company has long-term take-or-pay commitments with multiple shippers on the Waupisoo Pipeline who have collectively contracted for 80% to 90% of the capacity, subject to the timing of when shippers’ commitments commence and expire.

55

The Woodland Pipeline consists of Line 49 and Line 70 (Woodland Pipeline Extension) which were constructed in phases. In 2012, EPAI entered into a transportation agreement with Imperial Oil Resources Ventures Limited (IORVL) and ExxonMobil Canada Properties (ExxonMobil) to provide for the transportation of blended bitumen from the Kearl oil sands mine to the major Alberta pipeline hub at Edmonton. The construction of the Woodland Pipeline was phased with the Kearl oil sands mine expansion, with the first phase involving construction of a 140-kilometre (87-mile) 36-inch diameter pipeline from the mine to the Cheecham Terminal, and service on the Company’s existing Waupisoo Pipeline from Cheecham to the Edmonton area. The completed Woodland Pipeline (Line 49) was placed into service in 2013, commensurate with the start-up of the Kearl oil sands mine. The second phase involved the Woodland Pipeline Extension project, which under a joint venture among EPAI, IORVL and ExxonMobil, extended the Woodland Pipeline south from the Company’s Cheecham Terminal to its Edmonton Terminal. The extension involved the construction of a 385-kilometre (239-mile) 36-inch diameter pipeline which was completed and entered service in 2015, adding 379,000 bpd of capacity to the Regional Oil Sands System. The Company has long-term commitments on the Woodland Pipeline.

Results of Operations

Regional Oil Sands System adjusted EBIT for the year ended December 31, 2016 was $384 million compared with $341 million for the year ended December 31, 2015. The year-over-year increase in adjusted EBIT primarily reflected contributions from assets placed into service in the second half of 2015, including the Sunday Creek Terminal and Woodland Pipeline Extension projects that were placed into service in the third quarter of 2015 and the AOC Hangingstone Lateral which was completed in December 2015. Regional Oil Sands System adjusted EBIT also benefitted from higher contracted volumes on Waupisoo Pipeline in the fourth quarter of 2016 compared with the fourth quarter of 2015. However, the year-over-year increase in adjusted EBIT was partially offset by the effects of the wildfires in northeastern Alberta during the second quarter of 2016, as discussed under Liquids Pipelines – Impact of Wildfires in Northeastern Alberta, which negatively impacted Regional Oil Sands System adjusted EBIT by approximately $6 million.

Regional Oil Sands System adjusted EBIT for the year ended December 31, 2015 was $341 million compared with $301 million for the year ended December 31, 2014. Higher adjusted EBIT primarily reflected contributions from assets placed into service in 2014 and 2015, including the Sunday Creek Terminal and Woodland Pipeline Extension projects that were placed into service in the third quarter of 2015, Surmont Phase 2 Expansion project that was placed into service in phases in November 2014 and March 2015, as well as Norealis Pipeline which was completed in April 2014. These positive impacts were partially offset by higher depreciation expense from a larger asset base, as well as a reduction in contracted volumes on the Athabasca Mainline, mitigated in part by higher uncommitted volumes on this pipeline.

Line 37 Crude Oil Release

On June 22, 2013, Enbridge reported a release of an estimated 1,300 barrels of light synthetic crude oil on its Line 37 pipeline approximately two kilometres north of Enbridge’s Cheecham Terminal. The release was caused by unusually high water levels in the region that triggered ground movement on the right-of-way. The oil released from Line 37 was recovered and on July 11, 2013, Line 37 returned to service at reduced operating pressure. Normal operating pressure was restored on July 29, 2013 after finalization of geotechnical analysis. Investigations into the incident were conducted by the Alberta Energy Regulator and Environment Canada. Each of these investigations was completed and closed by the applicable regulator without any penalties or fines being imposed on Enbridge.

For the years ended December 31, 2015 and 2014, the Company’s EBIT reflected remediation and long-term stabilization costs of approximately $6 million and $5 million before insurance recoveries, respectively. Lost revenues associated with the shutdown of Line 37 and the pipelines sharing a corridor with Line 37 were minimal. At the time of the Line 37 crude oil release, Enbridge carried liability insurance for sudden and accidental pollution events, subject to a $10 million deductible.

56

The integrity and stability costs associated with remediating the impact of the high water levels were precautionary in nature and not covered by insurance. Enbridge expects to record receivables for amounts claimed for recovery pursuant to its insurance policies during the period that it deems realization of the claim for recovery to be probable. For the years ended December 31, 2016, 2015 and 2014, Enbridge recognized insurance recoveries of $5 million, $32 million and $10 million, respectively.

MID-CONTINENT AND GULF COAST

Mid-Continent and Gulf Coast includes Seaway and Flanagan South Pipelines, Spearhead Pipeline, as well as the Mid-Continent System that is managed by Enbridge through its subsidiary, EEP.

Seaway Pipeline

In 2011, Enbridge acquired a 50% interest in the 1,078-kilometre (670-mile) Seaway Crude Pipeline System (Seaway Pipeline), including the 805-kilometre (500-mile), 30-inch diameter long-haul system between Cushing, Oklahoma and Freeport, Texas, as well as the Texas City Terminal and Distribution System which serves refineries in the Houston and Texas City areas. Seaway Pipeline also includes 7.4 million barrels of crude oil tankage on the Texas Gulf Coast.

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

Flanagan South Pipeline

Flanagan South is a 950-kilometre (590-mile), 36-inch diameter interstate crude oil pipeline that originates at the Company’s terminal at Flanagan, Illinois and terminates in Cushing, Oklahoma. Flanagan South and associated pumping stations were completed in the fourth quarter of 2014 and the majority of the pipeline parallels Spearhead Pipeline’s right-of-way. Flanagan South has an initial design capacity of approximately 600,000 bpd; however, in its initial years, it is not expected to operate at its full design capacity.

Spearhead Pipeline

Spearhead Pipeline is a long-haul pipeline that delivers crude oil from Flanagan, Illinois, a delivery point on the Lakehead System to Cushing, Oklahoma. The pipeline was originally placed into service in 2006 and an expansion was completed in mid-2009, increasing capacity from 125,000 bpd to 193,300 bpd. Initial committed shippers and expansion shippers currently account for more than 70% of the 193,300 bpd capacity on Spearhead Pipeline. Both the initial committed shippers and expansion shippers were required to enter into 10-year shipping commitments at negotiated rates that were offered during the open season process. In March 2015, the commitment agreements with the initial committed shippers were extended for an additional 10 years. The balance of the capacity is currently available to uncommitted shippers on a spot basis at FERC approved rates.

Mid-Continent System

The Mid-Continent System is comprised of the Ozark Pipeline and storage terminals at Cushing, Oklahoma and Flanagan, Illinois. The Ozark Pipeline transports crude oil from Cushing, Oklahoma to Wood River, Illinois, where it delivers to a third-party refinery and interconnects with other third-party pipelines. In December 2016, the Company entered into an agreement to sell the Ozark Pipeline to a subsidiary of MPLX LP for cash proceeds of approximately $294 million (US$219 million), including $13 million (US$10 million) in reimbursable costs for additional capital spent by the Company up to the closing date of the transaction. Subject to certain pre-closing conditions, the transaction is expected to close by the end of the first quarter of 2017.

The storage terminals consist of 100 individual storage tanks ranging in size from 78,000 to 575,000 barrels. Of the approximately 23.6 million barrels of storage shell capacity on the Mid-Continent System, the Cushing terminal accounts for approximately 20.1 million barrels. A portion of the storage facilities is used for operational purposes, while the remainder of the facilities are contracted with various crude oil market participants for their term storage requirements.

57

Results of Operations

Mid-Continent and Gulf Coast adjusted EBIT for the year ended December 31, 2016 was $656 million compared with adjusted EBIT of $516 million for the year ended December 31, 2015. The year-over-year increase in adjusted EBIT reflected stronger operating performance, as well as the favourable effect of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2016 compared with 2015.

Excluding the impact of foreign exchange translation to Canadian dollars, Mid-Continent and Gulf Coast adjusted EBIT was US$495 million for the year ended December 31, 2016 compared with US$400 million for the year ended December 31, 2015. The year-over-year increase in adjusted EBIT primarily reflected higher transportation revenues resulting mainly from an increase in the level of committed take-or-pay volumes on Flanagan South, as well as higher tariffs on Flanagan South in the first half of 2016. Throughput on Flanagan South is affected by Canadian Mainline apportionment and the upstream apportionment experienced in the first half of 2015 was partially alleviated in 2016 with the expansion of the Company’s mainline system completed in the third quarter of 2015. When committed shippers on Flanagan South are unable to satisfy 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 onto the end of the contract term. Partially offsetting the year-over-year increase in adjusted EBIT was lower throughput on Spearhead Pipeline due to a decline in demand for services in the second half of 2016.

Excluding the impact of foreign exchange translation to Canadian dollars, the decline in shippers’ demand on Spearhead Pipeline also drove a decrease in Mid-Continent and Gulf Coast adjusted EBIT for the fourth quarter of 2016 compared with the fourth quarter of 2015.

As noted above, positively impacting adjusted EBIT for the year ended December 31, 2016 was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in 2016. 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.

Mid-Continent and Gulf Coast adjusted EBIT for the year ended December 31, 2015 was $516 million compared with adjusted EBIT of $319 million for the year ended December 31, 2014. The year-over-year increase in adjusted EBIT reflected stronger operating performance, as well as the favourable effect of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2015 compared with 2014.

Excluding the impact of foreign exchange translation to Canadian dollars, Mid-Continent and Gulf Coast adjusted EBIT was US$400 million for the year ended December 31, 2015 compared with US$287 million for the year ended December 31, 2014. The increase in adjusted EBIT primarily reflected the effects of Flanagan South and Seaway Pipeline Twin commencing operations in late 2014. During the first half of 2015, as a result of Canadian Mainline apportionment, throughput on Seaway Pipeline and Flanagan South was lower than the throughput committed on these pipelines. However, this upstream apportionment was partially alleviated in the second half of 2015 through the expansion of the Company’s mainline system completed in July 2015.

Also positively impacting year-over-year adjusted EBIT was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in 2015. As noted above, a portion of Mid-Continent and Gulf Coast United States dollar EBIT was hedged as part of the Company’s enterprise-wide financial risk management program. For further details refer to Eliminations and Other.

Seaway Pipeline Regulatory Matters

Seaway Pipeline filed an application for market-based rates in December 2011. In February 2014, the FERC rejected Seaway Pipeline’s application but also set out a new methodology based on recent appellate court rulings for determining whether a pipeline has market power and invited Seaway Pipeline to refile its market-based rate application consistent with the new policy. In December 2014, Seaway Pipeline filed a new market-based rates application. Several parties filed comments in opposition alleging that the application should be denied because Seaway Pipeline has market power in both its receipt and destination markets. On September 17, 2015, the FERC set the application for hearing before an Administrative Law Judge (ALJ). On December 1, 2016, the ALJ issued its decision which concluded that the Commission should grant the application of Seaway Pipeline for authority to charge market-based rates. The parties may file briefs during the first quarter of 2017, and the Commissioners will review the entire record and issue a decision. There is no timeline for the FERC Commissioners to act and issue a decision.

58

Additionally, in a February 1, 2016 order, the FERC upheld Seaway Pipeline’s current committed rate structure and reversed a prior ALJ decision reducing those rates to cost-based levels. With respect to the uncommitted rates, the FERC permitted Seaway Pipeline to include the full Enbridge purchase price (including goodwill) in rate base. FERC’s other cost-of-service rulings regarding the uncommitted rates were also largely favourable to Seaway Pipeline. A compliance filing calculating revised rates was filed on March 17, 2016. The FERC accepted the compliance filing by order dated August 17, 2016. Seaway Pipeline has filed new uncommitted rates in accordance with that order. Going forward, Seaway Pipeline’s uncommitted rates may be adjusted annually based on the FERC index, unless and until the FERC approves Seaway Pipeline’s application for market-based ratemaking authority.

SOUTHERN LIGHTS PIPELINE

Southern Lights Pipeline is a fully-contracted single stream pipeline that ships diluent from the Manhattan Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. This 180,000 bpd 16/18/20-inch diameter pipeline was placed into service mid-2010. Prior to the close of the Canadian Restructuring Plan, the Canadian portion of Southern Lights Pipeline (Southern Lights Canada) was owned by SL Canada, an Alberta limited partnership. Southern Lights US is owned by Enbridge Pipelines (Southern Lights) L.L.C., a Delaware limited liability company. Both Southern Lights Canada and Southern Lights US receive tariff revenues under long-term contracts with committed shippers. Tariffs provide for recovery of all operating and debt financing costs plus a return on equity (ROE) of 10%. Southern Lights Pipeline has assigned 10% of the capacity (18,000 bpd) for shippers to ship uncommitted volumes.

As part of Enbridge’s sponsored vehicle strategy, on November 7, 2014, the Fund Group subscribed for and purchased Southern Lights Class A units which provide a defined cash flow stream to the Fund Group and represent the equity cash flows derived from the core rate base of Southern Lights Pipeline until June 30, 2040 - see The Fund Group 2014 Drop Down Transaction. Enbridge has guaranteed payment of the quarterly distributions that the Fund Group receives, except in circumstances of force majeure, certain regulatory actions and shipper defaults that remain unrecovered under the shipper contracts. The Fund Group has options to negotiate extensions for two additional 10-year terms beyond 2040 and to participate in equity returns from future expansions of Southern Lights Pipeline.

In addition, as part of the Canadian Restructuring Plan, effective September 1, 2015, Enbridge transferred all Class B units of Southern Lights Canada to the Fund Group. Following the closing of the Transaction, the Fund Group holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights Canada. Enbridge continues to indirectly own all of the Class B Units of Southern Lights US.

Results of Operations

Southern Lights Pipeline adjusted EBIT for the year ended December 31, 2016 was $168 million compared with $155 million for the year ended December 31, 2015. The increase in year-over-year adjusted EBIT reflected higher recovery of negotiated depreciation rates in 2016 transportation tolls.

Southern Lights Pipeline adjusted EBIT for the year ended December 31, 2015 was $155 million compared with $121 million for the year ended December 31, 2014. The increase in year-over-year adjusted EBIT reflected higher recovery of negotiated depreciation rates in 2015 transportation tolls. Also positively impacting adjusted EBIT was the favourable impact of translating United States dollar earnings at a higher Average Exchange Rate in 2015 on the United States component of Southern Lights Pipelines.

59

BAKKEN SYSTEM

The Bakken System is a joint operation that includes a Canadian entity and a United States entity. The United States portion of the pipeline system extends from Berthold, North Dakota to the International Boundary near North Portal, North Dakota, and connects to the Bakken Canada entity at the border to bring the crude oil into Cromer, Manitoba. The United States portion of the Bakken System is comprised of a crude oil gathering and interstate pipeline transportation system servicing the Williston Basin in North Dakota and Montana, which includes the Bakken and Three Forks formation. The gathering pipelines collect crude oil from nearly 80 different receipt facilities located throughout western North Dakota and eastern Montana, including nearly 20 third-party gathering pipeline connections, with delivery to a variety of interconnecting pipeline and rail export facilities.

Tolls and Tariffs

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

Results of Operations

Bakken System adjusted EBIT for the year ended December 31, 2016 was $198 million compared with $213 million for the year ended December 31, 2015. The year-over-year decrease in adjusted EBIT reflected lower rates and lower rail revenues on the United States portion of the Bakken System. The decrease in adjusted EBIT was partially offset by the translation of United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2016 compared with 2015.

Excluding the impact of foreign exchange translation to Canadian dollars, adjusted EBIT from Bakken System’s United States portion was US$131 million compared with US$155 million for the corresponding 2015 period. The decrease in year-over-year adjusted EBIT for the United States portion of the Bakken System was attributable to lower surcharge revenues as certain surcharge rates subject to an annual adjustment were decreased effective April 1, 2016, as well as lower rail revenues related to EEP’s Berthold rail facility due to expired contracts. These negative impacts were partially offset by the effects of higher throughput driven by enhanced downstream capacity on the mainline system and as a result of volumes shifting to pipelines from other higher cost transportation alternatives such as rail.

As noted above, impacting adjusted EBIT for the year ended December 31, 2016 was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in 2016. Similar to Lakehead System, a portion of the United States dollar EBIT of the Bakken System in the United States 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.

Bakken System adjusted EBIT for the year ended December 31, 2015 was $213 million compared with $233 million for the year ended December 31, 2014. Within Bakken System adjusted EBIT for the year ended December 31, 2015 was US$155 million (2014 - US$198 million) from its United States’ operations.

Excluding the impact of foreign exchange translation to Canadian dollars, the decrease in year-over-year adjusted EBIT was primarily attributed to the United States portion of the Bakken System which experienced lower surcharge revenues as certain surcharge rates subject to an annual adjustment were decreased effective April 1, 2015, as well as higher power costs related to higher throughput on the system. The increase in throughput year-over-year partially offset the year-over-year adjusted EBIT decrease and was attributed to the system’s enhanced market access and volumes shifting onto the system from other higher cost alternatives such as transportation by rail.

In 2015, the United States portion of the Bakken System earnings were translated at a higher Average Exchange Rate. As noted above, a portion of the United States dollar EBIT from the Bakken System in the United States was hedged as part of the Company’s enterprise-wide financial risk management program. For further details refer to Eliminations and Other.

60

FEEDER PIPELINES AND OTHER

Feeder Pipelines and Other primarily includes the Company’s 85% interest in Olympic Pipe Line Company (Olympic), the largest refined products pipeline in the State of Washington, with a capacity to transport approximately 290,000 bpd of gasoline, diesel and jet fuel. It also includes the NW System, which transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta, interests in a number of liquids pipelines in the United States, including the recently completed Southern Access Extension, the Toledo Pipeline, which connects with the EEP mainline at Stockbridge, Michigan, and the Company’s 75% joint venture interest in Eddystone Rail, a unit-train unloading facility and related local pipeline infrastructure near Philadelphia, Pennsylvania that delivered Bakken and other light sweet crude oil to Philadelphia area refineries, as well as business development costs related to Liquids Pipelines activities. Due to a significant decrease in price spreads between Bakken crude oil and West Africa/Brent crude oil and increased competition in the region, demand for Eddystone Rail services dropped significantly, resulting in an impairment of this facility in the second quarter of 2016. Feeder Pipelines and Other also includes the Hardisty Contract Terminal and Hardisty Storage Caverns located near Hardisty, Alberta, a key crude pipeline hub in western Canada.

Also reported in Feeder Pipelines and Other results are contributions from the South Prairie Region assets which transport crude oil and NGL from producing fields and facilities in southeastern Saskatchewan and southwestern Manitoba to Cromer, Manitoba where products enter the mainline system to be transported to the United States or eastern Canada. On December 1, 2016, EIPLP completed the sale of the South Prairie Region assets to an unrelated party for cash proceeds of $1.08 billion. The sold assets consisted of certain liquids pipelines and related facilities in southeast Saskatchewan and southwest Manitoba, including the Saskatchewan Gathering and Weyburn gathering systems, as well as the Westspur trunk line. The shipper commercial arrangements and contracts associated with the South Prairie Region assets are expected to remain in place and the Company expects that the crude oil and NGL volumes delivered from the South Prairie Region assets will continue to flow onto Enbridge’s Canadian Mainline at Cromer.

Results of Operations

Feeder Pipelines and Other adjusted EBIT for the year ended December 31, 2016 was $196 million compared with $155 million for the year ended December 31, 2015. The year-over-year increase in adjusted EBIT primarily reflected new contributions from Southern Access Extension which was placed into service in the fourth quarter of 2015. These positive contributions were partially offset by a decrease in adjusted EBIT from Eddystone Rail, primarily attributable to market conditions which impacted volumes at the rail facility. Adjusted EBIT for the year ended December 31, 2016 also reflected lower contributions from Toledo Pipeline resulting from refinery turnarounds that negatively impacted volumes in the second and third quarters of 2016, as well as the absence of EBIT from the South Prairie Region assets in the month of December 2016.

Feeder Pipelines and Other adjusted EBIT for the year ended December 31, 2015 was $155 million compared with $119 million for the year ended December 31, 2014. The increase in adjusted EBIT was attributable to higher earnings from Eddystone Rail Project completed in April 2014, incremental earnings from certain storage agreements, higher tolls and throughput on Toledo Pipeline, contributions from Southern Access Extension which was placed into service in December 2015 and higher throughput from the South Prairie Region assets driven by volumes returning to the system from alternative transportation sources, such as rail. Partially offsetting the increase in adjusted EBIT were higher business development costs not eligible for capitalization in the first quarter of 2015, lower average tolls on the Olympic pipeline and higher property taxes relating to Toledo Pipeline in the third quarter of 2015.

Eddystone Rail Legal Matter

On February 2, 2017, Enbridge subsidiary Eddystone Rail Company, LLC, (Eddystone) filed an action against several defendants in the United States District Court for the Eastern District of Pennsylvania. Eddystone alleges that the defendants transferred valuable assets from Eddystone’s counterparty in a maritime contract, so as to avoid outstanding obligations to Eddystone. Eddystone is seeking payment of compensatory and punitive damages in excess of US$140 million. Eddystone’s chances of success in connection with the above noted action cannot be predicted and it is possible that Eddystone may not recover any of the amounts sought.

61

BUSINESS RISKS

The risks identified below are specific to the Liquids Pipelines business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks.

Asset Utilization

Enbridge is exposed to throughput risk under the CTS on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of Enbridge’s assets.

Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions outside of Enbridge’s control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on Enbridge’s pipelines. In the second quarter of 2016, extreme wildfires in northeastern Alberta resulted in a temporary curtailment of oil sands production from facilities in the vicinity of Fort McMurray, Alberta, resulting in a negative impact on the Company’s adjusted EBIT and ACFFO as discussed above. However, the long-term outlook for Canadian crude oil production, particularly from western Canada, and increasing United States domestic production indicates a growing source of potential supply of crude oil.

While take-or-pay and similar contractual arrangements on certain systems serve to mitigate exposure to the risks noted above, under certain contracts, committed shippers are provided with relief from their take-or-pay payment obligations to the extent such shippers are unable to ship committed volumes on a pipeline solely as a result of Canadian Mainline apportionment.

Enbridge seeks to mitigate utilization risks within its control. The market access expansion initiatives, which have had components placed into service over the past several years, and those currently under development have and are expected to further reduce capacity bottlenecks and enhance access to markets for customers. The Company also seeks to optimize capacity and throughput on its existing assets by working with the shipper community to enhance scheduling efficiency and communications, as well as makes continuous improvements to scheduling models and timelines to maximize throughput. Further to the day-to-day improvements sought by Enbridge, the Company is also undertaking the L3R Program, which upon completion, will support the safety and operational reliability of the overall system and enhance the flexibility on the mainline system allowing the Company to further optimize throughput. Throughput risk is partially mitigated by provisions in the CTS agreement, which allow Enbridge to adjust the applicable L3R Program surcharge if volumes fall below defined thresholds or to negotiate an amendment to the agreement in the event certain minimum threshold volumes are not met. Lastly, in February 2017, the Company acquired an interest in the Bakken Pipeline System, a growth project that will provide North Dakota producers enhanced access to premium light crude oil markets in both the eastern and western United States Gulf Coast. For further details and recent developments on this matter, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Bakken Pipeline System (EEP).

Operational and Economic Regulation

Operational regulation risks relate to failing to comply with applicable operational rules and regulations from government organizations and could result in fines or operating restrictions or an overall increase in operating and compliance costs.

Regulatory scrutiny over the integrity of liquids pipeline assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on the Company’s future earnings and the cost related to the construction of new projects. The Company believes operational regulation risk is mitigated by active monitoring and consulting on potential regulatory requirement changes with the respective regulators or through industry associations. The Company also develops robust response plans to regulatory changes or enforcement actions. While the Company believes the safe and reliable operation of its assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators to make unilateral decisions that could have a financial impact on the Company.

62

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

The Company believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of the Company’s liquids pipeline assets. The Company also involves its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations as well as in the establishment of tariffs and tolls on new and existing pipelines. However, despite the efforts of the Company to mitigate economic regulation risk, there remains a risk that a regulator could overturn long-term agreements between the Company and shippers or deny the approval and permits for new projects.

Renewal of Line 5 Easement

On January 4, 2017, the Tribal Council of the Bad River Band of Lake Superior Tribe of Chippewa Indians (the Band) voted not to renew its interest in certain Line 5 easements through the Bad River Reservation. Line 5 is included within the Company’s mainline system. The Band’s resolution calls for decommissioning and removal of the pipeline from all Bad River lands and watershed. The Tribal Resolution may impact the Company’s ability to operate the pipeline on the Reservation. Since the Band passed the resolution, the parties have held discussions about the possibility of engaging in a facilitated mediation process, with the objective of resolving the Band’s concerns on a long-term basis.

Competition

Competition may result in a reduction in demand for the Company’s services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets.

Other competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada, the United States and internationally represent competition to the Company’s liquids pipelines network. Competition also arises from proposed pipelines that seek to access markets currently served by the Company’s liquids pipelines, such as proposed projects to the Gulf Coast or eastern markets. Competition also exists from proposed projects enhancing infrastructure in the Alberta regional oil sands market. The Mid-Continent and Bakken systems also face competition from existing competing pipelines, proposed future pipelines and existing and alternative gathering facilities. Competition for storage facilities in the United States includes large integrated oil companies and other midstream energy partnerships. Additionally, volatile crude price differentials and insufficient pipeline capacity on either Enbridge or other competitor pipelines can make transportation of crude oil by rail competitive, particularly to markets not currently serviced by pipelines.

The Company believes that its liquids pipelines continue to provide attractive options to producers in the WCSB due to its competitive tolls and flexibility through its multiple delivery and storage points. Enbridge’s current complement of growth projects to expand market access and to enhance capacity on the Company’s pipeline system combined with the Company’s commitment to project execution is expected to further provide shippers reliable and long-term competitive solutions for oil transportation. The Company’s existing right-of-way for the mainline system also provides a competitive advantage as it can be difficult and costly to obtain rights of way for new pipelines traversing new areas. The Company also employs long-term agreements with shippers, which also mitigate competition risk by ensuring consistent supply to the Company’s liquids pipelines network.

63

Foreign Exchange and Interest Rate Risk

The CTS agreement for the Canadian Mainline exposes the Company to risks related to movements in foreign exchange rates and interest rates. Foreign exchange risk arises as the Company’s IJT under the CTS is charged in United States dollars. These risks have been substantially managed through the Company’s hedging program by using financial contracts to fix the prices of United States dollars and interest rates. Certain of these financial contracts do not qualify for cash flow hedge accounting and, therefore, the Company’s earnings are exposed to associated changes in the mark-to-market value of these contracts.

GAS DISTRIBUTION

EARNINGS BEFORE INTEREST AND INCOME TAXES

	2016		2015		2014
(millions of Canadian dollars)
Enbridge Gas Distribution Inc. (EGD)	393		342		305
Noverco Inc. (Noverco)	53		53		45
Other Gas Distribution and Storage	48		51		41
Adjusted earnings before interest and income taxes	494		446		391
EGD - (warmer)/colder than normal weather	(18	)	15		48
EGD - employee severance cost adjustment	10		6		-
Noverco - changes in unrealized derivative fair value loss	(6	)	(12	)	(7	)
Noverco - recognition of regulatory balances	17		-		-
Noverco - asset impairment	(5	)	-		-
Earnings before interest and income taxes	492		455		432

Adjusted EBIT from Gas Distribution was $494 million in 2016 compared with $446 million and $391 million in 2015 and 2014, respectively. EGD generated higher adjusted EBIT in 2016 primarily due to an increase in distribution charges arising from growth in EGD’s rate base, including customer growth. In 2016, adjusted EBIT from Other Gas Distribution and Storage reflected lower distribution revenues due to warmer weather in the New Brunswick region.

Additional details on items impacting Gas Distribution EBIT include:

·Noverco EBIT for 2016 included an asset impairment in relation to certain long-term assets not eligible for recovery through rates.

·Noverco EBIT for 2016 included the recognition of regulatory assets in relation to employee future benefits.

ENBRIDGE GAS DISTRIBUTION INC.

EGD is Canada’s largest natural gas distribution company and has been in operation for more than 160 years. It serves over two million customers in central and eastern Ontario and areas of northern New York State. EGD’s utility operations are regulated by the OEB and the New York State Public Service Commission.

Incentive Rate Plan

EGD’s 2016, 2015 and 2014 rates were set in accordance with parameters established by the customized IR Plan. The customized IR Plan was approved in 2014 by the OEB, with modifications, for 2014 through 2018, inclusive of the requested capital investment amounts and an incentive mechanism providing the opportunity to earn above the allowed ROE.

The customized IR Plan provides the methodology for establishing rates for the distribution of natural gas for a five-year period from 2014 through 2018. Within annual rate proceedings for 2015 through 2018, the customized IR Plan allows revenues and corresponding rates to be updated annually for select items including the rate of return to be earned on the equity component of its rate base. The OEB also approved the adoption of a new approach for determining net salvage percentages to be included within EGD’s approved depreciation rates, as compared with the traditional approach previously employed. The new approach results in lower net salvage percentages for EGD, and therefore lowers depreciation rates and future removal and site restoration reserves.

64

For the year ended December 31, 2016, EGD’s rates were set according to the OEB approved settlement agreement in December 2015 and the final rate order in May 2016. For the year ended December 31, 2015, EGD’s rates were set according to the OEB approved settlement agreement in April 2015 and the final rate order in May 2015. For the year ended December 31, 2014, EGD’s rates were set by the OEB’s July 2014 decision, and subsequent August 2014 decision and rate order in the Company’s customized IR application.

In order to align the interest of customers with the Company’s shareholders, the customized IR Plan includes an earnings sharing mechanism, whereby any return over the allowed rate of return for a given year under the customized IR Plan is to be shared equally with customers. For the years ended December 31, 2016, 2015 and 2014, EGD recognized $3 million subject to OEB approval, $7 million and $12 million, respectively, as a return of revenues to customers in relation to the earnings sharing mechanism.

Cap and Trade

Effective January 1, 2017, Ontario commenced a cap and trade program as part of changes intended to lower levels of GHG emissions across the province of Ontario. Under this program, there will be costs related to the GHG emissions from residential and commercial natural gas usage. The Government of Ontario has indicated the funds it collects through the cap and trade program will be allocated to other programs, such as energy conservation, aimed to reduce GHG emissions.

The Government of Ontario requires EGD to acquire GHG allowances to cover the applicable emissions from its residential and commercial customers’ usage of natural gas, as well as from emissions from the delivery of natural gas to these customers. Under an interim rate order approved by the OEB, EGD has started to recover cap and trade compliance costs through rates beginning January 1, 2017.

Results of Operations

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

	2016		2015		2014
(millions of Canadian dollars)
Adjusted earnings before interest and income taxes	393		342		305
Interest expense	(178	)	(153	)	(150	)
Income taxes	(14	)	(18	)	(10	)
Adjusting items in respect of:
Interest expense	3		4		-
Income taxes	(3	)	5		13
Adjusted earnings	201		180		158
EGD - (warmer)/colder than normal weather	(13	)	11		36
EGD - employee severance cost adjustment	7		4		-
EGD - changes in unrealized derivative fair value loss	(2	)	(3	)	-
Earnings attributable to common shareholders	193		192		194

EGD adjusted earnings for the year ended December 31, 2016 were $201 million compared with $180 million for the year ended December 31, 2015. The year-over-year increase in adjusted earnings primarily reflected higher distribution charges arising from growth in EGD’s rate base, including customer growth.

EGD adjusted earnings for the year ended December 31, 2015 were $180 million compared with $158 million for the year ended December 31, 2014. EGD’s higher adjusted earnings in 2015 were primarily attributable to an increase in distribution charges that resulted from an increased rate base, as well as customer growth during the year in excess of expectations embedded in rates.

65

NOVERCO

Enbridge owns an equity interest in Noverco through ownership of 38.9% of its common shares and an investment in preferred shares. Noverco is a holding company that owns approximately 71% of Gaz Métro Limited Partnership (Gaz Métro), a natural gas distribution company operating in the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in the province of Quebec and the state of Vermont. Noverco also holds, directly and indirectly, an investment in Enbridge common shares. A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred share investments which are based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%.

Results of Operations

Noverco adjusted EBIT of $53 million for the year ended December 31, 2016 was comparable with adjusted EBIT of $53 million for the year ended December 31, 2015. Gaz Métro realized higher adjusted operating earnings for 2016 due to a stronger United States dollar, and growth in both its regulated and non-regulated rate base. This was offset by lower wind energy production, as well as lower preferred share dividend income, driven by a lower Government of Canada bond reference rate re-setting. In addition to these factors, there was a decrease in Noverco adjusted EBIT for the fourth quarter of 2016 compared with the fourth quarter of 2015, primarily reflecting higher adjusted EBIT in the fourth quarter of 2015 due to the timing of equity earnings adjustments between quarters.

Noverco adjusted EBIT was $53 million for the year ended December 31, 2015 compared with $45 million for the year ended December 31, 2014. The increase in year-over-year adjusted EBIT reflected stronger operating earnings from Gaz Métro due to a favourable Average Exchange Rate on Gaz Métro’s United States based business and incremental contributions from new assets. Partially offsetting the higher adjusted EBIT was lower preferred share dividend income based on lower yield of 10-year Government of Canada bonds.

OTHER GAS DISTRIBUTION AND STORAGE

Other Gas Distribution includes natural gas distribution utility operations in Quebec and New Brunswick, the most significant being EGNB which is wholly-owned and operated by the Company. EGNB operates the natural gas distribution franchise in the province of New Brunswick, has approximately 11,800 customers and is regulated by the New Brunswick Energy and Utilities Board (EUB).

Results of Operations

Other Gas Distribution and Storage adjusted EBIT was $48 million for the year ended December 31, 2016 compared with $51 million for the year ended December 31, 2015. The decrease in year-over-year adjusted EBIT primarily reflected lower distribution revenues due to warmer weather in the New Brunswick region in 2016.

Other Gas Distribution and Storage adjusted EBIT was $51 million for the year ended December 31, 2015 compared with $41 million for the year ended December 31, 2014. The increase in adjusted EBIT reflected the absence of a loss that EGNB incurred in 2014 under a contract to sell natural gas to the province of New Brunswick. Due to an abnormally cold winter in the first quarter of 2014, costs associated with the fulfilment of the contract were higher than the revenues received. Excluding the impact of the above noted contract which expired in October 2014, EGNB adjusted EBIT increased slightly in 2015 due to higher distribution revenues.

Enbridge Gas New Brunswick Inc. – Regulatory Matters

The Company commenced two separate actions in 2012 and 2014, respectively, against the Government of New Brunswick in the New Brunswick courts. The first action sought recovery of damages alleged to have arisen due to various breaches of the General Franchise Agreement with EGNB, under which EGNB operates in the province. The second action sought damages for improper extinguishment of a deferred regulatory asset that was eliminated from EGNB’s Consolidated Statements of Financial Position in 2012, due to legislative and regulatory changes enacted by the Government of New Brunswick in that year.

66

By agreement finalized on December 16, 2016, the parties fully and finally settled both of the actions. EGNB’s franchise for gas distribution in New Brunswick was extended for 25 years beyond its original term ending in 2019, further extendable at EGNB’s option for another 25 years after that. The Province of New Brunswick also amended the laws governing gas distribution in the province to, among other things, provide EGNB with the opportunity to recover through rates during the agreed upon franchise extension period up to $145 million of the deferred regulatory asset rendered unavailable by the 2012 legislative and regulatory changes. Of this amount, $100 million is to be recoverable at a fixed rate of $4 million annually starting in the first year of the franchise extension term and the balance is recoverable throughout the future franchise term upon regulatory approval. While Enbridge considers the conditions of settlement and broader legislative changes enacted to achieve it as a favourable development for EGNB’s operating environment, EGNB’s recovery of the deferred regulatory asset over the future franchise period is not guaranteed and remains subject to the usual operational and regulatory factors applicable to recovery of deferred amounts.

BUSINESS RISKS

The risks identified below are specific to the Gas Distribution business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks.

Economic Regulation

The utility operations of Gas Distribution are regulated by the OEB and EUB among others. Regulators’ future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which Gas Distribution operates. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position, or that would have been recorded on the Consolidated Statements of Financial Position in absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded.

The Company seeks to mitigate economic regulation risk. The Company retains dedicated professional staff and maintains strong relationships with customers, intervenors and regulators. The terms of rate negotiations are reviewed by the Company’s legal, regulatory and finance teams. The five-year customized IR Plan approved in 2014 provides a level of stability by having a long-term agreement with the OEB which allows EGD to recover its expected capital investments under the agreement, as well as an opportunity to earn above the OEB allowed ROE. Under the customized IR Plan, EGD is permitted to recover, with OEB approval, certain costs that were beyond management control, but that were necessary for the maintenance of its services. The customized IR Plan also includes a mechanism to reassess the customized IR Plan and return to cost of service if there are significant and unanticipated developments that threaten the sustainability of the customized IR Plan.

Environmental Regulation

EGD’s workers, operations and facilities are subject to municipal, provincial and federal legislation which regulates the protection of the environment and the health and safety of workers. For the environment, this includes the regulation of discharges to air, land and water; the management and disposal of solid and hazardous waste; and the assessment of contaminated sites. Failing to comply with regulations could expose EGD to fines or operating restrictions.

In May 2016, the Government of Ontario passed legislation to establish a cap and trade program in the province of Ontario. Under the legislation, EGD is required to meet GHG compliance obligations by purchasing emission allowances for EGD and its customers. In September 2016, the OEB issued its regulatory framework for the assessment of costs of natural gas utilities’ cap and trade activities, addressing regulatory requirements for implementation of cap and trade. In November 2016, EGD filed its compliance plan with the OEB and also received approval of an interim rate order for the recovery of cap and trade compliance costs through rates beginning January 1, 2017.

In 2016, EGD was required to report 2015 GHG emissions to the Ontario Ministry of Environmental and Climate Change from combustion sources only in Ontario, and all reported data was verified by a third party. There were no issues identified for the 2015 reporting year. EGD monitors developments and attends external stakeholder consultations in Ontario. EGD utilizes a carbon data management system to help with the data capture and mandatory and voluntary reporting needs of EGD. EGD continues to publicly report its GHG emissions and will continue to develop internal procedures to identify operational related GHG reductions.

67

In July 2016, EGD received $58 million from the Government of Ontario for the purpose of carrying out the Green Investment Fund (GIF) program. The purpose of the GIF program is to reduce GHG emissions in the residential sector. EGD’s use of the funds is limited to eligible expenditures for the purpose of executing the program. There is no earnings impact related to the GIF program and any unspent funds will be returned to the Government of Ontario at the expiry of the agreement on May 31, 2019, or sooner if the Government of Ontario elects to terminate the agreement at any time prior to its expiration date.

Natural Gas Cost Risk

EGD’s regulated business does not profit from the sale of natural gas nor is it at risk for the difference between the actual cost of natural gas purchased and the price approved by the OEB for inclusion in distribution rates. This difference is deferred as a receivable from or payable to customers until the OEB approves its refund or collection. EGD monitors the balance and its potential impact on customers and may request interim rate relief to recover or refund the natural gas cost differential. While the cost of natural gas does not impact EGD’s earnings, it does affect the amount of EGD’s investment in gas in storage. The OEB also determines the timing of payment or collection from customers which can have an impact on EGD’s working capital during the period in which costs are expected to be recovered.

EGNB is also subject to natural gas cost risk as increases in natural gas prices that cannot be fully recovered from customers in the current period can negatively impact cash flow. Increased commodity costs will also impact the amount that may be charged in future distribution rates due to EGNB’s regulatory structure.

Volume Risk

Since customers are billed on a volumetric basis, EGD’s ability to collect its total revenue requirement (the cost of providing service) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers.

Weather is a significant driver of delivery volumes, given that a significant portion of EGD’s customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continue to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption.

Sales and transportation of gas for customers in the residential and small commercial sectors account for approximately 80% of total distribution volume. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Customer additions from all market sectors are important as continued expansion adds to the total consumption of natural gas.

Even in those circumstances where EGD attains its total forecast distribution volume, it may not earn its expected ROE due to other forecast variables, such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector. EGNB is also subject to volume risk as the impact of weather conditions on demand for natural gas could result in earnings fluctuations.

EGD remains at risk for the actual versus forecast large volume contract commercial and industrial volumes; however, general service volume risk is mitigated for both ratepayers and EGD through a deferral account.

68

GAS PIPELINES AND PROCESSING

EARNINGS BEFORE INTEREST AND INCOME TAXES

	2016		2015		2014
(millions of Canadian dollars)
Aux Sable	(2	)	(3	)	45
Alliance Pipeline	184		151		135
Vector Pipeline	31		28		24
Canadian Midstream	107		87		60
Enbridge Offshore Pipelines (Offshore)	58		14		12
US Midstream	5		73		30
Other	(17	)	(14	)	(13	)
Adjusted earnings before interest and income taxes	366		336		293
Aux Sable - asset impairment loss	(37	)	-		-
Aux Sable - accrual for commercial arrangements	-		(30	)	-
Alliance Pipeline - changes in unrealized derivative fair value gains/(loss)	10		(15	)	(6	)
Alliance Pipeline - derecognition of regulatory balances	-		8		-
Offshore - gain on sale of non-core assets	-		6		22
US Midstream - changes in unrealized derivative fair value gains/(loss)	(149	)	(62	)	180
US Midstream - goodwill impairment loss	-		(440	)	-
US Midstream - assets impairment loss	(14	)	(20	)	(18	)
US Midstream - loss on disposal of non-core assets	(4	)	-		-
US Midstream - make-up rights adjustment	(1	)	1		(4	)
US Midstream - transfer of contracts	-		(13	)	-
Earnings/(loss) before interest and income taxes	171		(229	)	467

Adjusted EBIT from Gas Pipelines and Processing was $366 million in 2016 compared with adjusted EBIT of $336 million and $293 million in 2015 and 2014. The year-over-year increase in adjusted EBIT was driven primarily by operational efficiencies achieved by Alliance Pipeline, higher adjusted EBIT from Offshore reflecting contributions from Heidelberg Pipeline which was placed into service in January 2016, as well as increase in adjusted EBIT from Canadian Midstream reflecting contributions from the Tupper Plants acquired on April 1, 2016. Partially offsetting these increases were unfavourable market conditions in US Midstream in 2016, resulting in a year-over-year decrease in adjusted EBIT from lower volumes due to reduced drilling by producers.

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

·Aux Sable EBIT for 2016 included an asset impairment charge related to certain underutilized assets at Aux Sable US’ NGL extraction and fractionation plant.

·US Midstream EBIT for 2015 included a goodwill impairment charge related to the Company’s United States natural gas and NGL businesses due to a prolonged decline in commodity prices which has reduced producers’ expected drilling programs and negatively impacted volumes on the Company’s natural gas and NGL systems.

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

·US Midstream EBIT for 2016 reflected asset impairment charges in relation to certain non-core trucking assets that the Company sold in the third quarter of 2016.

·US Midstream EBIT for 2015 and 2014 reflected asset impairment charges in relation to a non-core propylene pipeline asset, following finalization of a contract restructuring with the primary customer.

69

AUX SABLE

Enbridge owns a 42.7% interest in Aux Sable US and Aux Sable Midstream US, and a 50% interest in Aux Sable Canada (together, Aux Sable). Aux Sable US owns and operates an NGL extraction and fractionation plant at Channahon, Illinois, outside Chicago, near the terminus of Alliance Pipeline. The plant extracts NGL from the liquids-rich natural gas transported on Alliance Pipeline as necessary for Alliance Pipeline to meet gas quality specifications of downstream transmission and distribution companies and to take advantage of positive fractionation spreads. The fractionation facilities at the Channahon Plant were expanded in 2016 in order to handle the increasing NGL content of the Alliance Pipeline’s gas stream.

Aux Sable US sells its NGL production from the base plant to a single counterparty under a long-term contract. Aux Sable receives a fixed annual fee and a share of any net margin generated from the business in excess of specified natural gas processing margin thresholds (the upside sharing mechanism). In addition, Aux Sable is compensated for all operating and maintenance costs for the base plant, and subject to certain limits, costs incurred to source feedstock supply and capital costs associated with its facilities. The counterparty supplies all make-up gas and fuel gas requirements for the base plant. The contract is for an initial term of 20 years, expiring March 31, 2026, and may be extended by mutual agreement for 10-year terms. NGL production associated with the expanded fractionation facilities is sold by a third party marketer, on behalf of Aux Sable, under a three year contract.

Aux Sable also owns facilities upstream of Alliance Pipeline that facilitate deliveries of liquids-rich gas volumes into the pipeline for further processing at the Aux Sable plant. These facilities include the Palermo Conditioning Plant and the Prairie Rose Pipeline in the Bakken area of North Dakota, owned and operated by Aux Sable Midstream US; and Aux Sable Canada’s interests in the Montney area of British Columbia, comprising the Septimus Pipeline and a 22% interest it acquired effective October 1, 2015 in the Septimus and Wilder Gas Plants, in exchange for its previously held 50% ownership interest in the Septimus Plant.

Aux Sable Canada has contracted capacity on the Septimus Pipeline and the Septimus and Wilder Gas Plants to a producer under a 10-year take-or-pay contract, which provides for a return on and of invested capital. Actual operating costs are recovered from the producer. In 2016, the Palermo Gas Plant and the Prairie Rose Pipeline were contracted to producers under either take-or-pay, area dedication or fee for service contracts, with contract terms out to 2020. Gas processed at the Palermo Plant in 2016 averaged 53 mmcf/d. Throughput on the Prairie Rose Pipeline in 2016 averaged 100 mmcf/d. In addition, revenues are earned by Aux Sable based on a sharing of available NGL margin with producers.

In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the United States EPA for alleged violations of the Clean Air Act related to the Leak Detection and Repair program, and related provisions of the Clean Air Act permit for Aux Sable’s Channahon, Illinois facility. As part of the ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believed to be an exceedance of currently permitted limits for Volatile Organic Material. In April 2015, a second NFOV from the EPA was received in connection with this potential exceedance. Aux Sable engaged in discussions with the EPA to evaluate the impacts and ultimate resolution of these issues, including with respect to a draft Consent Decree, and those discussions are continuing. The Consent Decree, when finalized, is not expected to have a material impact.

On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on the Company’s consolidated financial position or results of operations.

Results of Operations

Aux Sable reported adjusted loss before interest and taxes of $2 million for the year ended December 31, 2016 comparable with adjusted loss before interest and taxes of $3 million for the year ended December 31, 2015. Aux Sable’s operations include both a Canadian and United States component. Within Aux Sable adjusted loss before interest and taxes for the year ended December 31, 2016 was US$2 million from its United States’ operations compared with adjusted EBIT of US$4 million for the year ended December 31, 2015.

70

The slight year-over-year decrease in Aux Sable adjusted loss before interest and taxes was the result of a reduction in gas purchase costs and overhead cost savings within the Canadian business, and lower NGL transport costs within the North Dakota business. These favourable variances were partially offset by higher NGL feedstock costs at the Aux Sable US plant associated with an increase in Rich Gas Premium (RGP) contract volumes. There were no earnings contributions from the upside sharing mechanism in either 2016 or 2015 as a result of low fractionation margins. Aux Sable also reported lower adjusted loss before interest and income taxes for the fourth quarter of 2016 compared with the fourth quarter of 2015, primarily due to lower quarter-over-quarter feedstock supply costs.

Aux Sable reported adjusted loss before interest and taxes of $3 million for the year ended December 31, 2015 compared with adjusted EBIT of $45 million for the year ended December 31, 2014. Within Aux Sable adjusted EBIT for the year ended December 31, 2015 was US$4 million from its United States’ operations compared with US$30 million for the year ended December 31, 2014. Lower fractionation margins resulting from a weaker commodity price environment, absence of contributions from the upside sharing mechanism, costs associated with feedstock supply and the loss of a producer processing contract at the Palermo Conditioning Plant were the main drivers behind the decreases in adjusted EBIT in 2015 compared with 2014.

Aux Sable Feedstock Supply

Aux Sable secures NGL feedstock for its Channahon Plant primarily through RGP contracts with producers, with varying terms ranging up to a maximum of seven years. RGP contracts provide for producers and Aux Sable to share in the value of the liquids-rich natural gas (both residual dry gas and extracted NGL) transported on the Alliance Pipeline. Effective December 1, 2015, Canadian producers contracted for firm transportation service under Alliance Pipeline’s New Service Framework, and either transport volumes to Aux Sable’s Channahon Plant or to the new Alliance Trading Point, notionally located on Alliance Pipeline Canada. Aux Sable purchases RGP gas volumes delivered to the Alliance Trading Point and through corresponding gas sales contracts, assignments or other arrangements with counterparties, Aux Sable facilitates the transport of purchased gas to the Channahon Plant. For further details on the Alliance Pipeline recontracting, refer to Gas Pipeline and Processing – Alliance Pipeline – Alliance Pipeline New Services Framework.

Heat Content Management

Aux Sable is under contract with Alliance Pipeline to provide heat content management services to ensure natural gas exiting the Aux Sable Channahon Plant meets gas quality specifications of downstream transmission and distribution companies, including NGL content (i.e. heat content). Aux Sable monitors the quality of the plant’s outlet gas stream on a continuous basis. In 2016, Aux Sable completed an expansion of its fractionation capacity in order to handle increasing volumes of NGLs delivered to the plant. Aux Sable is assessing various options with respect to heat content management as the heat content of the natural gas delivered by Alliance Pipeline is expected to increase in the future.

Business Risks

The risks identified below are specific to Aux Sable. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks.

Commodity Price Risk

Aux Sable’s NGL margin earned through the upside sharing mechanism is subject to commodity price risk arising from the price differential between the cost of natural gas and the value achieved from the sale of extracted NGL after the fractionation process. Aux Sable is also subject to the value of natural gas on the Alliance Pipeline supplied by certain of its RGP producers. To mitigate this natural gas supply risk, Aux Sable has entered into a variety of contracts with counterparties. Commodity price risk created from Aux Sable’s RGP contracts and through the upside sharing mechanism is closely monitored and must comply with its formal risk management policies that are consistent with the Company’s risk management practices. These risks may be mitigated by Aux Sable or through the Company’s risk management activities.

71

Asset Utilization

A decrease in gas volumes or a decrease in the NGL content of the gas stream delivered by Alliance Pipeline to the Aux Sable plant can directly and adversely affect margins earned. Aux Sable is well-positioned to offer RGP contracts, when necessary, to producers within the liquids-rich Montney, Duvernay and Bakken plays that are located in close proximity to Alliance Pipeline to mitigate these risks.

ALLIANCE PIPELINE

The Alliance Pipeline, which includes both Alliance Pipeline Canada and Alliance Pipeline US, consists of approximately 3,000 kilometres (1,864 miles) of integrated, high-pressure natural gas transmission pipeline and approximately 860 kilometres (534 miles) of lateral pipelines and related infrastructure. Alliance Pipeline transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub downstream of the Aux Sable NGL extraction and fractionation plant at Channahon, Illinois. Alliance Pipeline US and Alliance Pipeline Canada have annual firm service shipping capacity to deliver 1.455 billion cubic feet per day (bcf/d) and 1.325 bcf/d, respectively. Natural gas transported on Alliance Pipeline downstream of the Aux Sable plant can be delivered to two local natural gas distribution systems in the Chicago area and five interstate natural gas pipelines, providing shippers with access to midwest and eastern natural gas markets.

Alliance Pipeline New Services Framework

Effective December 1, 2015, Alliance Pipeline commenced operations under its New Services Framework. Prior to December 1, 2015, Alliance Pipeline successfully re-contracted its annual firm service capacity with an average contract length of approximately five years. As part of the Canadian portion of the New Services Framework, the NEB granted pricing discretion for interruptible transportation and seasonal firm service with all associated revenues accruing to Alliance Pipeline Canada. The FERC, as part of its acceptance of Alliance Pipeline US’ New Services Framework, set all issues related to the proposed elimination of Authorized Overrun Service and Interruptible Transportation revenue crediting, and the maintenance of Alliance Pipeline US’ existing recourse rates, for hearing. In 2016, the FERC expanded the issues set for hearing to include aspects of the Alliance Pipeline US tariff that relate to liquids extraction requirements. The FERC approved Alliance Pipeline US’ negotiated rate contracts, which are not set for hearing. Throughout 2016, Alliance Pipeline US conducted settlement hearings with all interested parties, which culminated in the certification of a contested settlement issued to the FERC Commissioners on September 6, 2016, by a FERC ALJ. No Alliance Pipeline US customer contested the settlement. On December 15, 2016, the FERC Commissioners approved essentially all aspects of the contested settlement, except for the liquids extraction matter, which has been set for hearing, with any outcomes to be effective on a prospective basis. Alliance Pipeline has accepted the approved portions of the FERC Commissioners’ decision and is seeking rehearing of the decision regarding liquids extraction.

Pursuant to the New Services Framework, Alliance Pipeline retains exposure to potential variability in revenues generated from market based services provided beyond contracted annual firm transport service, as well as certain future costs. As such, the majority of Alliance Pipeline’s operations no longer meet all of the criteria required for the continued application of rate-regulated accounting treatment.

Alliance Pipeline Transportation Services Agreements

Prior to December 1, 2015, Alliance Pipeline Canada had transportation service agreements (TSAs) with shippers for substantially all of its available firm transportation capacity. The TSAs were designed to provide toll revenues sufficient to recover prudently incurred costs of service, including operating and maintenance, depreciation, an allowance for income tax, costs of indebtedness and an allowed ROE of 11.26% after-tax, based on a deemed 70/30 debt-to-equity ratio. Alliance Pipeline US had similar TSAs which allowed for the recovery of the cost of service, which included operating and maintenance costs, the cost of financing, an allowance for income tax, an annual allowance for depreciation and an allowed ROE of 10.88%. In addition, Alliance Pipeline US negotiated non-renewal charges that were an exit fee for shippers that did not elect to extend their transportation contracts. The initial term of the TSAs expired in December 2015, with the exception of a small proportion of shippers that elected to extend their contracts beyond 2015.

72

Results of Operations

Alliance Pipeline reported adjusted EBIT of $184 million for the year ended December 31, 2016, which represents EBIT from the Company’s 50% equity investment in Alliance Pipeline, compared with adjusted EBIT of $151 million for the year ended December 31, 2015. The year-over-year increase in adjusted EBIT was primarily due to lower operating costs and lower depreciation expense as a result of an extension to the useful life of the pipeline assets. Alliance revenues were lower in 2016 resulting from the New Services Framework that commenced in the fourth quarter of 2015; however, earnings from the New Services Framework benefitted from strong demand for seasonal firm service. These positive effects were partially offset by the absence of the 2015 non-renewal fees for Alliance Pipeline US.

Alliance Pipeline reported adjusted EBIT of $151 million for the year ended December 31, 2015 compared with adjusted EBIT of $135 million for the year ended December 31, 2014. This increase in adjusted EBIT was attributable to lower operating costs, a stronger United States dollar and strong demand in December 2015 for interruptible service under its New Services Framework. These increases were partially offset by a shutdown of Alliance Pipeline Canada for six days in August 2015 after an amount of hydrogen sulfide entered its mainline pipeline through an upstream operator, which resulted in Alliance Pipeline issuing demand charge credits to its shippers.

Business Risks

The risks identified below are specific to Alliance Pipeline. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks.

Asset Utilization

Currently, natural gas pipeline capacity out of the WCSB exceeds supply. Alliance Pipeline to date has been relatively unaffected by this excess capacity environment as Alliance Pipeline is situated in the growing Montney, Duvernay and Bakken areas and was successfully recontracted. Alliance Pipeline is also the only liquids-rich gas export pipeline within the WCSB. Further, Alliance Pipeline accesses large natural gas markets and, following extraction and fractionation at the Aux Sable NGL extraction and fractionation plant, delivers NGL to growing NGL markets. As noted above, Alliance Pipeline’s New Services Framework also allows for the provision of services beyond annual firm transport service, at market rates, further supporting asset utilization.

Competition

Alliance Pipeline faces competition for pipeline transportation services to the Chicago area from both existing pipelines and proposed pipeline projects from existing and new gas developments throughout North America. Any new or upgraded pipelines could either allow shippers greater access to natural gas markets or offer natural gas transportation services that are more desirable than those provided by Alliance Pipeline because of location, facilities or other factors. In addition, any new, existing, or upgraded pipelines could charge tolls or rates or provide transportation services to locations that result in greater net profit for shippers, with the effect of reducing future supply for Alliance Pipeline. The ability of Alliance Pipeline to cost-effectively transport liquids-rich gas and its proximity to the liquids-rich Montney, Duvernay and Bakken plays serve to enhance its competitive position.

Economic Regulation

Alliance Pipeline is subject to regulation by the NEB in Canada and the FERC in the United States. Under the New Services Framework, effective December 1, 2015, Alliance Pipeline has contracted with shippers under terms as approved by the NEB in Canada and the FERC in the United States. Firm service tolls are fixed for the duration of the contracts’ terms.

VECTOR PIPELINE

Vector, which includes both the Canadian and United States portions of the pipeline system, consists of 560 kilometres (348 miles) of mainline natural gas transmission pipeline between the Chicago, Illinois hub and a storage complex at Dawn, Ontario. Vector’s primary sources of supply are through interconnections with Alliance Pipeline, Northern Border Pipeline and Guardian Pipeline in Joliet, Illinois. Vector has the capacity to deliver a nominal 1.3 bcf/d and in 2016 it operated at or near capacity. The Company provides operating services to and holds a 60% joint venture interest in Vector.

73

Results of Operations

Vector adjusted EBIT for the year ended December 31, 2016 was $31 million compared with adjusted EBIT of $28 million for the year ended December 31, 2015. Vector’s operations include a Canadian and United States component. Within Vector adjusted EBIT for the year ended December 31, 2016 was US$21 million from its United States’ operations compared with adjusted EBIT of US$20 million for the year ended December 31, 2015. Excluding the impact of foreign exchange translation to Canadian dollars, Vector adjusted EBIT, which represents EBIT from the Company’s equity investment in Vector, was slightly higher for the year ended December 31, 2016 compared with the year ended December 31, 2015. The positive effect of lower interest costs due to a declining debt balance, more than offset lower year-over-year transportation revenues. Initial long-haul transportation contracts terminated in 2016 as expected and capacity was re-contracted at lower market based rates.

Vector adjusted EBIT for the year ended December 31, 2015 was $28 million compared with $24 million for the year ended December 31, 2014. Within Vector adjusted EBIT for the year ended December 31, 2015 was US$20 million (2014 - US$18 million) from its United States’ operations. Excluding the impact of foreign exchange translation to Canadian dollars, Vector adjusted EBIT for the year ended December 31, 2015 was comparable to the corresponding 2014 period. The positive effects of lower operating expenses were offset by lower year-over-year transportation revenues as unusually high demand for natural gas transport was experienced during abnormal winter weather conditions in the first quarter of 2014. The slight increase in EBIT was due to a stronger United States dollar compared with the Canadian dollar. EBIT from the United States portion of Vector was translated at a higher Average Exchange Rate in 2015 compared with 2014 resulting in the overall increase in Vector adjusted EBIT in 2015.

Transportation Contracts

Vector’s total long haul capacity was fully contracted under firm service agreements at December 31, 2016. Long and short haul transportation service on the U.S segment of the system is contracted with shippers under a combination of both FERC approved negotiated rate service agreements and FERC tariff recourse rate service agreements.

In 2016, the remaining initial long-term firm service shippers, representing 255 mmcf/d, restructured their agreements and extended their terms to 2020 and beyond. There are now no more initial long-term contracts with early termination or annual extension rights.

In late 2014 and early 2015, Vector signed precedent agreements with both the proposed NEXUS Pipeline (Nexus) project and Energy Transfer Partners L.P.’s Rover Pipeline (Rover) project, to provide transportation service to the Dawn natural gas market hub. The Rover project received FERC approval on February 2, 2017 and is expected to commence deliveries into Vector in late 2017. The Nexus project is expected to receive FERC approval later in 2017, the timing of which will delay the start of construction, thereby delaying initial deliveries into Vector until the second half of 2018.

Transportation service on Vector is provided through a number of different forms of service agreements, including Firm Transportation Service, Interruptible Transportation Service and Backhaul Service. Vector is an interstate natural gas pipeline with FERC and NEB approved tariffs that establish the rates, terms and conditions governing its service to customers. On the United States portion of Vector, maximum tariff rates are determined using a cost of service methodology and maximum tariff changes may only be implemented upon approval by the FERC. For 2016, the FERC-approved maximum tariff rates included an underlying weighted average after-tax ROE component of 12.75%. On the Canadian portion, Vector is required to file its negotiated tolls calculation with the NEB on an annual basis. Tolls are calculated on a levelized basis that include a rate of return incentive mechanism based on construction costs and are subject to a rate cap. In 2016, maximum tolls on the Canadian portion include an ROE component of 10.48% after-tax.

Business Risks

The risks identified below are specific to Vector. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks.

74

Asset Utilization

Vector has been minimally impacted by the excess natural gas supply environment that exists throughout North America, mainly as a result of its long-term firm service contracts. Vector has entered into precedent agreements to provide transport service to both the Rover and Nexus proposed pipeline projects that will extend back to the Marcellus/Utica supply basin. Rover is expected to commence deliveries into Vector in late 2017, and Nexus in 2018. Once both projects are in service, these arrangements will effectively fill all available delivery capacity to Dawn, Ontario from current contract roll-offs scheduled through 2019. Current firm service contracts that amount to approximately 60% of long haul capacity are scheduled to expire during 2017 and 2018.

Competition

Vector faces competition to transport natural gas into Ontario, Canada and other eastern markets from primarily the Marcellus supply region, which may reduce Vector deliveries sourced from its traditional interconnected pipelines in the United States Midwest. Vector manages this risk by focusing on developing long-term relationships with its customers and by providing them value added services. In addition, as discussed above, Vector is expected to commence firm service transport based on precedent agreements with respect to the Rover Pipeline and NEXUS Pipeline projects. Vector will reach its eastern delivery capacity once these projects are in service.

Economic Regulation

The United States portion of Vector is subject to regulation by the FERC. If tariff rates are protested, the timing and amount of any recovery or refund of amounts recorded on the Consolidated Statements of Financial Position could be different from the amounts that are eventually recovered or refunded. In addition, future profitability of the entities could be negatively impacted.

CANADIAN MIDSTREAM

At December 31, 2016, Canadian Midstream consisted of the wholly-owned Tupper Plants located within the Montney shale play in northeastern British Columbia, the Company’s 71% interest in the Cabin Gas Plant (Cabin) located 60 kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin, as well as interests in the Pipestone and Sexsmith gathering systems (together, Pipestone and Sexsmith). The Company has almost 100% interest in Pipestone and the primary producer and operator of Pipestone holds a nominal 0.01% interest. The Company also has varying interests (55% to 100%) in Sexsmith and its related sour gas gathering, compression and NGL handling facilities, located in the Peace River Arch region of northwest Alberta. Enbridge is the operator of the Tupper Plants and Cabin.

The Canadian Midstream investments are underpinned by 20-year take-or-pay contracts with producers. Return on and of capital is based on the actual costs to purchase or construct the facilities. The Company is not impacted by throughput volumes; however, the Company shares in revenues obtained from available capacity sold to third parties or on volumes that exceed producer take-or-pay levels. Operating costs are passed through to producers.

In April 2016, Enbridge acquired the Tupper Plants as described under Growth Projects – Commercially Secured Projects. The Tupper Plants are designed to process low hydrogen sulfide natural gas and remove a modest level of NGL in order to meet downstream natural gas pipeline specifications.

Phase 1 of Cabin is currently 98% completed. Cabin producers are expected to request the Company to commission and start-up Phase 1 once the natural gas price recovers to a more economic level to support the Horn River Basin’s dry gas production. Phase 2 construction is approximately 40% complete and is in preservation mode awaiting producer’s requests for completion. In December 2012, the Company started earning fees on its total investment made to date on both Phases 1 and 2.

Results of Operations

Canadian Midstream adjusted EBIT was $107 million for the year ended December 31, 2016 compared with adjusted EBIT of $87 million for the year ended December 31, 2015. The increase in year-over-year adjusted EBIT reflected contributions from the Tupper Plants following their acquisition on April 1, 2016. Contributions from the Company’s investment in Cabin, Pipestone and Sexsmith were comparable year-over-year.

75

Canadian Midstream adjusted EBIT was $87 million for the year ended December 31, 2015 compared with adjusted EBIT of $60 million for the year ended December 31, 2014. Higher adjusted EBIT reflected an increase in take-or-pay fees on the Company’s investment in Cabin, Pipestone and Sexsmith. Pipestone adjusted EBIT also increased as a result of volumes that exceeded take-or-pay levels and due to a full year of incremental adjusted EBIT from the final phase placed into service in June 2014.

Business Risks

The risks identified below are specific to Canadian Midstream. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks.

Asset Utilization

The Tupper Plants are located within the core of the Montney shale play, which continues to be developed by a number of producers. Although this area of the Montney contains a lower level of NGL content than others, production is supported by strong economics, the result of high initial production rates, ultimate recoveries and predictable low drilling and completion costs, making it one of the most competitive natural gas production regions in North America.

Cabin is located in the prolific Horn River Basin, one of the largest gas shale plays in North America. The current low gas price environment has slowed development due to the remote location and the lack of NGL content to supplement producer economics. Accelerated development of the Horn River is expected to be primarily tied to the development of LNG exports currently being pursued by Cabin producers. The nearby Cordova Embayment and Liard Basin share similar characteristics as the Horn River; however, they are at an earlier stage of development.

Pipestone and Sexsmith are located within the liquids-rich Peace River Arch region which has seen significant development by area producers. In 2016, throughput volumes exceeded take-or-pay levels.

ENBRIDGE OFFSHORE PIPELINES

Offshore is comprised of 11 active natural gas gathering and FERC-regulated transmission pipelines and two active oil pipelines, including the Heidelberg Pipeline that was placed in service in January 2016. These pipelines are located in four major corridors in the Gulf of Mexico, extending to deepwater developments, and include almost 2,100 kilometres (1,300 miles) of underwater pipe and onshore facilities with total capacity of approximately 6.5 bcf/d.

Results of Operations

Offshore adjusted EBIT was $58 million for the year ended December 31, 2016 compared with adjusted EBIT of $14 million for the year ended December 31, 2015. Excluding the impact of foreign exchange translation to Canadian dollars, Offshore adjusted EBIT for the year ended December 31, 2016 was US$44 million compared with US$11 million for the year ended December 31, 2015. The year-over-year increase in Offshore adjusted EBIT primarily reflected contributions from Heidelberg Pipeline which was placed into service in January 2016 and an increase in volumes in the Mississippi Canyon Gas Pipeline in the first half of 2016, partially offset by a decrease in volumes in the Garden Banks Gas Pipeline in the second half of 2016. Finally, the higher year-over-year adjusted EBIT also reflected the favourable impact of translating United States dollar earnings at a higher Average Exchange Rate in 2016.

Offshore adjusted EBIT was $14 million for the year ended December 31, 2015 compared with adjusted EBIT of $12 million for the year ended December 31, 2014. Excluding the impact of foreign exchange translation to Canadian dollars, Offshore adjusted EBIT of US$11 million for the year ended December 31, 2015 was comparable with US$12 million for the year ended December 31, 2014. Adjusted EBIT for both years reflected persistent weak gas volumes due to decreased production in the Gulf of Mexico. For the year ended December 31, 2015, Offshore incurred losses from equity investments in certain joint venture pipelines which were offset by contributions from the Jack St. Malo portion of WRGGS that was completed in December 2014. Finally, the higher adjusted EBIT also reflected the favourable impact of translating United States dollar earnings at a higher Average Exchange Rate in 2015.

76

Transportation Contracts

The primary shippers on the Offshore systems are producers who execute life-of-lease commitments in connection with transmission and gathering service contracts. In exchange, Offshore provides firm capacity for the contract term at an agreed upon rate. The firm capacity made available generally reflects the lease’s maximum sustainable production. The transportation contracts allow the shippers to define a maximum daily quantity over the expected production life. Some contracts have minimum throughput volumes that are subject to ship-or-pay criteria, but also provide the shippers with flexibility, subject to advance notice criteria, to modify the projected maximum daily quantity schedule to match current delivery expectations. The majority of long-term contracts have fixed transport rates, with revenue generation directly tied to actual production deliveries. Some of the systems operate under a cost-of-service methodology, including certain lines under FERC regulation.

The business model to be utilized for the WRGGS, Big Foot Pipeline, Heidelberg Pipeline and Stampede Pipeline projects differs from the historic model. These new projects have a base level return that is locked in through either ship-or-pay commitments or fixed demand charge payments. If volumes meet or exceed a producer’s anticipated levels, the return on these projects may increase. In addition, Enbridge has minimal capital cost risk on these projects and commercial agreements continue to contain life-of-lease commitments. The WRGGS and Big Foot Pipeline project agreements provide for recovery of actual capital costs to complete the project in fees payable by producers over the contract term. The Stampede Pipeline project provides for a capital cost risk sharing mechanism whereby Enbridge is exposed to a portion of the capital costs in excess of an agreed upon target. Conversely, Enbridge can recover in fees from producers a portion of the capital cost savings below the agreed upon target. Adjustments are allowed for certain of the Heidelberg Pipeline’s project variables that impact its cost, with Enbridge bearing the residual capital cost risk after these adjustments have been applied.

Business Risks

The risks identified below are specific to Offshore. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks.

Asset Utilization

A decrease in gas volumes transported by Offshore natural gas pipelines can directly affect revenues and EBIT. Low natural gas prices, in part due to the prevalence of onshore shale gas, have resulted in reduced investment in offshore exploration activities and producing infrastructure. Offshore diversifies its risk of declining gas production through the construction of crude oil pipelines. A decline in crude oil prices for a sustained period of time could change the potential for future investment opportunities. Further, a sustained decline in either natural gas or crude oil commodity prices could also impact the ability of the Company to recover its investment in long-lived offshore assets.

Competition

There is competition for new and existing business in the Gulf of Mexico, with multiple parties competing to construct and operate export pipelines for future deepwater discoveries. Offshore has been able to capture key opportunities, often allowing it to more fully utilize existing capacity. Offshore’s gas pipelines serve a number of strategically located deepwater host platforms, positioning it favourably to make incremental investments for new platform connections and receive additional transportation volumes from new developments that may be tied back to existing host platforms. Offshore is also able to construct pipelines to transport crude oil, diversifying the risk of declining gas production, as demonstrated with the Big Foot Pipeline, Heidelberg Pipeline and Stampede Pipeline projects. Due to natural production decline, offshore pipelines often have available capacity, resulting in significant competition for new developments in the Gulf of Mexico. Competitive dynamics may impact the ability of the Company to recover its investment in long-lived offshore assets.

Natural Disaster Incidents

Adverse weather, such as hurricanes and tropical storms, may impact Offshore’s financial performance directly or indirectly. Direct impacts may include damage to offshore facilities resulting in lower throughput, as well as inspection and repair costs. Indirect impacts may include damage to third party production platforms, onshore processing plants and pipelines that may decrease throughput on Offshore’s systems.

The occurrence of hurricanes in the Gulf of Mexico increases the cost, associated deductibles and availability of insurance coverage and as a result, the Company does not carry windstorm insurance coverage. Enbridge facilities are engineered to withstand hurricane forces and regular monitoring of extreme weather allows for timely evacuation of personnel and shutdown of facilities; however, damages to assets or injuries to personnel may still occur.

77

US MIDSTREAM

US Midstream consists of the Anadarko, East Texas, North Texas and Texas Express NGL systems, which include natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. In addition, US Midstream has rail and liquids marketing operations. Enbridge’s ownership interest in US Midstream, held through EEP, was 19.0% as at December 31, 2016 (December 31, 2015 - 19.2%).

Results of Operations

US Midstream adjusted EBIT was $5 million for the year ended December 31, 2016 compared with $73 million for the year ended December 31, 2015. Excluding the impact of foreign exchange translation to Canadian dollars, US Midstream adjusted EBIT was US$4 million for the year ended December 31, 2016 compared with US$57 million for the year ended December 31, 2015. The year-over-year decreases in US Midstream adjusted EBIT reflected lower volumes primarily attributable to the continued low commodity price environment which resulted in reduced drilling by producers. The decrease in adjusted EBIT was partially offset by lower operating costs.

US Midstream adjusted EBIT was $73 million for the year ended December 31, 2015 compared with $30 million for the year ended December 31, 2014. The year-over-year increase in adjusted EBIT reflected improved operating performance, as well as the favourable effect of translating United States dollar earnings to Canadian dollars at higher Average Exchange Rate in 2015 compared with 2014. Adjusted EBIT was positively impacted in 2015 by cost reduction efforts undertaken by management resulting in a decrease in contract labour costs and repairs and maintenance costs. Partially offsetting these positive impacts were lower volumes primarily as a result of reduced drilling programs by producers.

As noted above, impacting year-over-year adjusted EBIT is the effect of translating United States dollar earnings to Canadian dollars. The Average Exchange Rate fluctuates period-over-period with a resulting impact on adjusted EBIT. Similar to Lakehead System, a portion of US Midstream United States dollar EBIT is hedged as part of the Company’s enterprise-wide risk mitigation strategy and realized gains and losses from the foreign exchange derivatives instruments are reported within Eliminations and Other. For further details refer to results of Eliminations and Other.

Midcoast Energy Partners, L.P. – Drop Down of Interests and Privatization

EEP holds its natural gas and NGL midstream assets through a combination of direct holding and indirect holdings through MEP, a publicly listed partnership trading on the New York Stock Exchange. On July 1, 2014, EEP completed the sale of a 12.6% limited partnership interest in its natural gas and NGL midstream business to its subsidiary, MEP, for cash proceeds of US$350 million. Upon finalization of this transaction, EEP continued to retain a 2% GP interest, an approximate 52% limited partner interest and all IDR in MEP. However, EEP’s direct interest in entities or partnerships holding the natural gas and NGL midstream operations reduced from 61% to 48%, with the remaining ownership held by MEP. The completion of this transaction resulted in a partial monetization of EEP’s natural gas and NGL midstream business through sale to noncontrolling interests (being MEP’s public unitholders).

As discussed under United States Sponsored Vehicle Strategy, in May 2016, EEP announced that it was exploring various strategic alternatives for its investments in MEP and Midcoast Operating L.P., the operating subsidiary of MEP. On January 27, 2017, Enbridge announced that it had entered into a merger agreement through a wholly-owned subsidiary, whereby it will take private MEP by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US$170 million in the second quarter of 2017.

Business Risks

The risks identified below are specific to US Midstream. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks.

78

Asset Utilization

US Midstream natural gas gathering, processing and transportation assets are subject to market fundamentals affecting natural gas, NGL and related products. Commodity prices impact the willingness of natural gas producers to invest in additional infrastructure to produce natural gas and, with current low natural gas prices, infrastructure plans have been increasingly deferred or cancelled. These assets are also subject to competitive pressures from third-party and producer-owned gathering systems.

Supply for the marketing operations depends to a large extent on the natural gas reserves and rate of drilling within the areas served by the natural gas business. Demand is typically driven by weather-related factors, with respect to power plant and utility customers, and industrial demand. The US Midstream marketing business uses third party storage to balance supply and demand factors.

Economic Regulation

US Midstream’s economic regulation is driven primarily through certain activities within its intrastate natural gas pipelines, which are regulated by state regulators. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on US Midstream’s revenues and earnings. Delays in regulatory approvals could result in cost escalations and construction delays, which also negatively impact operations. Additionally, while the gas gathering pipelines are not currently subject to FERC rate regulation, proposals to more actively regulate intrastate gathering pipelines are currently being considered in certain of the states in which US Midstream operates. In addition, the FERC has also taken an interest in regulating gas gathering systems that connect into interstate pipelines.

Competition

Other interstate and intrastate natural gas pipelines (or their affiliates) and other midstream businesses that gather, treat, process and market natural gas or NGL represent competition to US Midstream. The level of competition varies depending on the location of the gathering, treating and processing facilities. However, most natural gas producers and owners have alternate gathering, treating and processing facilities available to them, including those owned by competitors that are substantially larger than US Midstream.

US Midstream’s marketing segment has numerous competitors, including large natural gas marketing companies, marketing affiliates of pipelines, major oil and natural gas producers, independent aggregators and regional marketing companies.

Commodity Price Risk

US Midstream is subject to commodity price risk arising from movements in natural gas and NGL prices and differentials. These risks have been partially mitigated by using physical and financial contracts to fix the prices of natural gas and NGL. Certain of these financial contracts do not qualify for cash flow hedge accounting; therefore, US Midstream’s EBIT is exposed to associated changes in the mark-to-market value of these contracts.

OTHER

Other is primarily comprised of business development activites for the Company’s gas pipelines businesses and Canadian Midstream and related costs not eligible for capitalization.

79

GREEN POWER AND TRANSMISSION

EARNINGS BEFORE INTEREST AND INCOME TAXES

	2016		2015	2014
(millions of Canadian dollars)
Green Power and Transmission	165		175	151
Adjusted earnings before interest and income taxes	165		175	151
Green Power and Transmission - changes in unrealized derivative fair value gains/(loss)	2		2	(2	)
Green Power and Transmission - investment impairment loss	(13	)	-	-
Earnings before interest and income taxes	154		177	149

Green Power and Transmission includes approximately 1,900 MW of net operating renewable and alternative energy sources. Of this amount, approximately 930 MW of net power generating capacity comes from wind farms located in the provinces of Alberta, Ontario and Quebec and approximately 780 MW of net power generating capacity comes from wind farms located in the states of Colorado, Texas, Indiana and West Virginia, including the 103-MW New Creek Wind Project which entered service in late December 2016. The vast majority of the power produced from these wind farms is sold under long-term PPAs. The Company also has three solar facilities located in Ontario and a solar facility located in Nevada, with 100 MW and 50 MW, respectively, of net power generating capacity. Also included in Green Power and Transmission is the Montana-Alberta Tie-Line, the Company’s first power transmission asset, a transmission line from Great Falls, Montana to Lethbridge, Alberta.

Results of Operations

Adjusted EBIT from Green Power and Transmission was $165 million for the year ended December 31, 2016 compared with adjusted EBIT of $175 million for the year ended December 31, 2015. Within Green Power and Transmission adjusted EBIT for the year ended December 31, 2016 was US$27 million (2015 - US$27 million) from its United States’ operations.

Excluding the impact of foreign exchange translation to Canadian dollars, adjusted EBIT decreased year-over-year as a result of disruptions at certain eastern Canadian wind farms in the first quarter and fourth quarter of 2016 due to weather conditions which caused icing of blades, as well as weaker wind resources experienced at certain facilities in Canada. These negative effects were partially offset by stronger wind resources at the Company’s United States wind farms during the second half of 2016.

Adjusted EBIT from Green Power and Transmission was $175 million for the year ended December 31, 2015 compared with adjusted EBIT of $151 million for the year ended December 31, 2014. Within Green Power and Transmission adjusted EBIT for the year ended December 31, 2015 was US$27 million (2014 - US$30 million) from its United States’ operations.

Excluding the impact of foreign exchange translation to Canadian dollars, the year-over-year increase in adjusted EBIT reflected contributions from new wind farms including Blackspring Ridge which commenced commercial operations in the second quarter of 2014 as well as incremental contributions associated with the purchase of additional interests in the Lac Alfred and Massif du Sud wind projects, which closed in the fourth quarter of 2014. However, the United States operations experienced a slight decrease in adjusted EBIT due to weaker wind resources at Cedar Point wind farm.

Adjusted EBIT for the years ended December 31, 2016 and 2015 reflected the favourable impact of translating United States dollar earnings at a higher year-over-year Average Exchange Rate in each of 2016 and 2015 on the United States businesses within Green Power and Transmission.

BUSINESS RISKS

The risks identified below are specific to the Green Power and Transmission business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks.

80

Asset Utilization

Earnings from Green Power and Transmission assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Green Power and Transmission projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at any of the Green Power and Transmission facilities could lead to decreased earnings and cash flows for the Company. Additionally, inefficiencies or interruptions of Green Power facilities due to operational disturbances or outages resulting from weather conditions or other factors, could also impact earnings. The Company mitigates the risk of operational availability by establishing Operations and Maintenance contracts with the original equipment manufacturers that include a negotiated operational performance asset guarantee. The Company also monitors the operational performance and reliability of the assets on a 24-hour basis.

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

Competition

The Company’s Green Power and Transmission assets operate in the North American power markets, which are subject to competition and the supply and demand balance for power in the provinces and states in which they operate. The renewable energy market sector includes large utilities and small independent power producers, which are expected to aggressively compete with the Company for project development opportunities.

ENERGY SERVICES

EARNINGS BEFORE INTEREST AND INCOME TAXES

	2016		2015	2014
(millions of Canadian dollars)
Energy Services	28		61	42
Adjusted earnings before interest and income taxes	28		61	42
Energy Services - changes in unrealized derivative fair value gains/(loss)	(205	)	264	688
Energy Services - custom duties paid on settlement of dispute	(8	)	-	-
Earnings/(loss) before interest and income taxes	(185	)	325	730

Following are additional details on Energy Services EBIT:

·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.

·Adjusted EBIT for 2014 excluded a realized loss in 2014 of $193 million incurred to close out certain forward derivative financial contracts intended to hedge the value of committed physical transportation capacity in certain markets accessed by Energy Services, but were determined to be no longer effective in doing so.

Energy Services provides energy supply and marketing services to North American refiners, producers and other customers. Crude oil and NGL marketing services are provided by Tidal Energy. This business transacts at many North American market hubs and provides its customers with various services, including transportation, storage, supply management, hedging programs and product exchanges. Tidal Energy is primarily a physical barrel marketing company focused on capturing value from quality, time and location differentials when opportunities arise. To execute these strategies, Energy Services may lease storage or rail cars, as well as hold nomination or contractual rights on both third party and Enbridge-owned pipelines and storage facilities. Tidal Energy also provides natural gas marketing services, including marketing natural gas to optimize commitments on certain natural gas pipelines.

81

Additionally, Tidal Energy provides natural gas supply, transportation, balancing and storage for third parties, leveraging its natural gas marketing expertise and access to transportation capacity.

Any commodity price exposure created from Tidal Energy’s physical business is closely monitored and must comply with the Company’s formal risk management policies. To the extent transportation costs and other fees exceed the basis (location) differential, earnings will be negatively affected.

Results of Operations

Adjusted EBIT from Energy Services was $28 million for the year ended December 31, 2016 compared with adjusted EBIT of $61 million for the year ended December 31, 2015. Reported within Energy Services adjusted EBIT for the year ended 2016 was US$32 million (2015 - US$31 million) from its United States operations.

Excluding the year-over-year favourable impact of foreign exchange translation to Canadian dollars, the decrease in adjusted EBIT in 2016 reflected weaker performance from Energy Services’ Canadian and United States operations during the first half of 2016. The compression of certain crude oil location and quality differentials and the impact of a weaker NGL market drove a year-over-year decrease in adjusted EBIT. This decrease was partially offset by the translation of United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2016, as well as positive contributions from increased crude oil storage opportunities in the second half of 2016. The positive crude oil storage opportunities were also a driver for the increase in adjusted EBIT in the fourth quarter of 2016 compared with the fourth quarter of 2015. 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.

Adjusted EBIT from Energy Services was $61 million for the year ended December 31, 2015 compared with adjusted EBIT of $42 million for the year ended December 31, 2014. Reported within Energy Services adjusted EBIT for the year ended December 31, 2015 was US$31 million (2014 - US$60 million loss before interest and income taxes) from its United States’ operations.

Excluding the year-over-year favourable impact of foreign exchange translation to Canadian dollars, the increase in adjusted EBIT in 2015 compared with 2014 reflected strong refinery demand for certain crude oil feedstock leading to more favourable storage management opportunities. Also contributing to the year-over-year increase in adjusted EBIT were losses realized in the first quarter of 2014 on certain financial contracts intended to hedge the value of committed transportation capacity, but which were not effective in doing so. During the second and fourth quarters of 2014, the Company closed out a forward component of these derivative contracts which had been determined to be no longer effective.

Business Risks

The risks identified below are specific to Energy Services. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks.

Commodity Price Risk

Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Volatility in commodity prices and changing marketing conditions could limit margin opportunities. Furthermore, commodity prices could have negative earnings and cash flow impacts if the cost of the commodity is greater than resale prices achieved by the Company. Energy Services activities are conducted in compliance with and under the oversight of the Company’s formal risk management policies, which require the implementation of hedging programs to manage exposure to changes in commodity prices, inclusive of exposures inherent within forecasted transactions.

Competition

Energy Services earnings are generated from arbitrage opportunities which, by their nature, can be replicated by other competitors. An increase in market participants entering into similar arbitrage transactions could have an impact on the Company’s earnings. The Company’s efforts to mitigate competition risk includes diversification of its marketing business by trading at the majority of major hubs in North America and establishing long-term relationships with clients.

82

ELIMINATIONS AND OTHER

EARNINGS BEFORE INTEREST AND INCOME TAXES

	2016		2015		2014
(millions of Canadian dollars)
Operating and administrative	(101	)	(74	)	(80	)
Realized foreign exchange derivative gains/(loss)	(297	)	(238	)	8
Other	49		66		12
Adjusted loss before interest and income taxes	(349	)	(246	)	(60	)
Changes in unrealized derivative fair value gains/(loss)	417		(694	)	(387	)
Unrealized intercompany foreign exchange gains/(loss)	(43	)	131		16
Employee severance and restructuring costs	(92	)	(47	)	(6	)
Project development and transaction costs	(81	)	-		-
Drop down transaction costs	-		(41	)	(35	)
Asset impairment loss	-		(2	)	-
Gain on sale of assets	-		-		16
Loss before interest and income taxes	(148	)	(899	)	(456	)

Items impacting Eliminations and Other EBIT include:

·Employee severance and restructuring costs incurred in 2016 in relation to the Company’s Building Our Energy Future initiative. For additional information, refer to Corporate Vision and Strategy – Strategy – Maintain the Foundation – Attract, Retain and Develop Highly Capable People.

·Project development and transaction costs incurred in 2016 in relation to the proposed Merger Transaction. For additional information, refer to Merger Agreement with Spectra Energy.

Eliminations and Other includes operating and administrative costs and foreign exchange costs which are not allocated to business segments. Eliminations and Other also includes new business development activities and general corporate investments.

Included in Eliminations and Other adjusted loss before interest and income taxes for the year ended December 31, 2016 was a realized loss of $297 million (2015 - $238 million loss; 2014 - $8 million gain) related to settlements under the Company’s foreign exchange risk management program. The Company targets to hedge 80% or more of anticipated consolidated United States denominated earnings from its United States operations utilizing foreign exchange derivative contracts with the objective of enhancing the predictability of its Canadian dollar earnings and ACFFO.

The notional amount of foreign currency derivatives realized during 2016 was US$1,044 million (2015 - US$952 million; 2014 - US$910 million) with an average price to sell United States dollars for Canadian dollars at $1.04 (2015 - $1.03; 2014 - $1.11). The Average Exchange Rate for the year ended December 31, 2016 was $1.32 (2015 - $1.28; 2014 - $1.10).

As the hedge rate was lower than the Average Exchange Rate in 2016 and 2015, the Company recognized realized hedge losses in each of these periods. The realized hedge loss for the year ended December 31, 2016 was greater than the comparative 2015 period due to higher notional amount of foreign currency derivatives and a greater unfavourable spread between the Average Exchange Rate and hedge rate. The realized loss in Eliminations and Other serves to partially offset the positive effect of translating the earnings performance of United States dollar denominated businesses at the 2016 Average Exchange Rate of $1.32 which is reflected in the reported EBIT of the applicable business segments. In 2014, the hedge rate approximated the Average Exchange Rate and therefore the realized gain was not significant.

Realized gains and losses on this hedging program are reported in their entirety within Eliminations and Other as the Company manages the foreign exchange risk of its United States businesses at an enterprise-wide level. Gains and losses arising on settlements of foreign exchange derivatives hedging transactional exposure from foreign denominated revenues or expenses within the Company’s Canadian businesses are captured at the business level and reported as part of the EBIT of the applicable segment.

83

For example, gains and losses on hedges of the Canadian Mainline’s United States dollar denominated revenue are reported as part of the EBIT from Canadian Mainline. For further details on the Company’s other risk management programs refer to Risk Management and Financial Instruments – Market Risk – Foreign Exchange Risk.

Eliminations and Other adjusted EBIT also reflected higher operating and administrative costs in 2016 primarily due to higher depreciation expense resulting from additions to intangible assets, computer hardware and leasehold improvements, as well as lower recoveries from other business segments.

Other adjusted EBIT decreased from $66 million for the year ended December 31, 2015 to $49 million for the year ended December 31, 2016. The decrease in adjusted EBIT reflected realized foreign exchange losses from the translation of certain intercompany transactions. The increase in adjusted EBIT in 2015 when compared with the corresponding 2014 period was the result of realized foreign exchange gains from the translation of certain intercompany transactions.

LIQUIDITY AND CAPITAL RESOURCES

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

The Company’s financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives, including utilization of its sponsored vehicles. For additional information, refer to Sponsored Vehicles below.

CAPITAL MARKET ACCESS

The Company and its self-funding subsidiaries ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive. In accordance with its funding plan, the Company completed the following capital market issuances in 2016:

Entity	Type of Issuance	Amount
(millions of Canadian dollars, unless stated otherwise)
Enbridge	Common shares	2,300
Enbridge	Preference shares	750
Enbridge	United States dollar term notes	US$1,500
Enbridge	Fixed-to-floating subordinated term notes	US$750
ENF	Common shares	575
EGD	Medium-term notes	300
EPI (via the Fund Group)	Medium-term notes	800

84

Bank Credit and Liquidity

To ensure ongoing liquidity and mitigate the risk of capital market disruption, Enbridge maintains ready access to funds through committed bank credit facilities and it actively manages its bank funding sources to optimize pricing and other terms. The following table provides details of the Company’s committed credit facilities at December 31, 2016 and 2015.

			2016			2015
			Total			Total
December 31,		Maturity	Facilities	Draws1	Available	Facilities
(millions of Canadian dollars)
Enbridge		2017-2020	8,183	4,700	3,483	6,988
Enbridge (U.S.) Inc.		2018-2019	3,934	126	3,808	4,470
EEP		2018-2020	3,525	2,293	1,232	3,598
EGD		2018-2019	1,017	360	657	1,010
The Fund		2019	1,500	236	1,264	1,500
Enbridge Pipelines (Southern Lights) L.L.C.		2018	27	-	27	28
EPI		2018	3,000	1,032	1,968	3,000
Enbridge Southern Lights LP		2018	5	-	5	5
MEP		2018	900	564	336	1,121
Total committed credit facilities			22,091	9,311	12,780	21,720
1	Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.

In 2016, the Company further diversified its access to funding through the establishment of two term credit facilities with syndicates of Asian banks for a total commitment of $968 million. These facilities were fully drawn upon in the second quarter of 2016 and provided a cost effective source of United States dollar term debt financing when compared with the cost of term debt financing in the United States public market at the time.

In addition to the committed credit facilities noted above, the Company also maintains $335 million (2015 - $349 million) of uncommitted demand facilities, of which $177 million (2015 - $185 million) were unutilized as at December 31, 2016.

The Company’s net available liquidity of $14,274 million at December 31, 2016 was inclusive of $2,117 million of unrestricted cash and cash equivalents and net of bank indebtedness of $623 million as reported on the Consolidated Statements of Financial Position.

The Company’s credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment may be required if the Company were to default on payment or violate certain covenants. As at December 31, 2016, the Company was in compliance with all debt covenants and expects to continue to comply with such covenants.

Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled Enbridge to manage its credit profile. The Company actively monitors and manages key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to total capital. As at December 31, 2016, the Company’s debt capitalization ratio was 62.1% compared with 65.5% as at December 31, 2015.

Following the Company’s announcement of the Merger Transaction, the Company’s credit ratings were affirmed as follows:

·DBRS Limited (DBRS) confirmed the Company’s issuer rating and medium-term notes and unsecured debentures rating of BBB (high), preference share rating of Pfd-3 (high) and commercial paper rating of R-2 (high), but changed their rating outlook from stable to under review, with developing implications.

85

·Moody’s Investor Services, Inc. affirmed the Company’s issuer rating and medium-term notes and unsecured debt rating of Baa2, preference share rating of Ba1 and commercial paper rating of P-2, and retained a negative outlook.

·Standard & Poor’s Rating Services (S&P) affirmed the Company’s corporate credit rating and 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 the Company’s global overall short-term rating of A-2. S&P also upgraded Enbridge’s pro forma financial risk profile to “significant” from “aggressive” due to the improved risk profile and projected credit metrics of the combined Company.

Enbridge’s solid investment grade credit rating is a reflection of the low risk nature of the underlying assets and limited exposure to commodity prices and volume risk; its project execution track record; strong dividend coverage; and substantial standby liquidity. The Company continues to execute its growth capital program and believes that it continues to have access to capital markets in both Canada and the United States to adequately fund the execution of its growth capital program.

The Company invests surplus cash in short-term investment grade money market instruments with highly creditworthy counterparties. Short-term investments were $800 million as at December 31, 2016 compared with $27 million as at December 31, 2015. The higher short-term investment balances at the end of 2016 reflect the temporary investment of a portion of capital markets funding undertaken by the Company in the fourth quarter pending its redeployment in growth capital program. At December 31, 2016, all short-term money market investments were rated not less than R-1 (low), A and A2 by DBRS, S&P and Moody’s Investor Services, Inc., respectively.

There are no material restrictions on the Company’s cash with the exception of the restricted cash of $68 million, which includes EGD’s receipt of cash from the Government of Ontario to fund its GIF program, cash collateral and for specific shipper commitments. Cash and cash equivalents held by EEP and the Fund Group are generally not readily accessible by Enbridge until distributions are declared and paid by these entities, which occurs quarterly for EEP and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative uses by Enbridge.

Excluding current maturities of long-term debt, at December 31, 2016 and 2015 the Company had a negative working capital position of $456 million and $1,227 million, respectively. In both periods, the major contributing factor to the negative working capital position was the ongoing funding of the Company’s growth capital program.

To address this negative working capital position, the Company maintains significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due. As at December 31, 2016, the net available liquidity totalled $14,274 million (2015 - $10,325 million). It is anticipated that any current maturities of long-term debt will be refinanced upon maturity.

December 31,		2016		2015
(millions of Canadian dollars)
Cash and cash equivalents1		2,185		1,049
Accounts receivable and other2		4,992		5,437
Inventory		1,233		1,111
Bank indebtedness		(623	)	(361	)
Short-term borrowings		(351	)	(599	)
Accounts payable and other3		(7,417	)	(7,399	)
Interest payable		(333	)	(324	)
Environmental liabilities		(142	)	(141	)
Working capital		(456	)	(1,227	)
1	Includes Restricted cash.
2	Includes Accounts receivable from affiliates.
3	Includes Accounts payable to affiliates.

86

SOURCES AND USES OF CASH

December 31,	2016		2015		2014
(millions of Canadian dollars)
Operating activities	5,211		4,571		2,547
Investing activities	(5,192	)	(7,933	)	(11,891	)
Financing activities	1,102		2,973		9,770
Effect of translation of foreign denominated cash and cash equivalents	(19	)	143		59
Increase/(decrease) in cash and cash equivalents	1,102		(246	)	485

Significant sources and uses of cash for the years ended December 31, 2016 and December 31, 2015 are summarized below:

Operating Activities

2016

·The growth in cash flow delivered by operations in 2016 is a reflection of the positive operating factors discussed under Performance Overview – Adjusted EBIT and Performance Overview –Adjusted Earnings, 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. Enbridge’s 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 the Company’s businesses, as well as timing of cash receipts and payments.

2015

·The growth in cash flow delivered by operations in 2015 compared with 2014 is also a reflection of the positive operating factors discussed under Performance Overview – Adjusted EBIT and Performance Overview – Adjusted Earnings, which primarily include higher throughput on the Canadian Mainline, higher volumes and tolls on the Lakehead System, contributions from new liquids pipeline assets placed into service in recent years and strong refinery demand for crude oil feedstock leading to more favourable storage management opportunities for Energy Services. Partially offsetting these positive factors were higher financing costs associated with funding of the Company’s growth program.

·Changes in operating assets and liabilities included within operating activities resulted in a cash outflow of $645 million for the year ended December 31, 2015 compared with an outflow of $1,699 million for the comparative 2014 period. The favourable variance for changes in operating assets and liabilities was attributable primarily to a negative impact in early 2014 related to significantly higher natural gas prices combined with colder weather which lead to increased natural gas demand within the Company’s gas distribution business, resulting in the Company accumulating a significant regulatory receivable as at December 31, 2014. A significant portion of these regulatory receivables was settled in 2015. Partially offsetting the favourable variance was higher inventory in Energy Services, as a result of increased activity in conjunction with the completion of the Seaway Pipeline Twin and Flanagan South projects in late 2014.

87

Investing Activities

The Company continues with the execution of its growth capital program which is further described in Growth Projects – Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.

A summary of additions to property, plant and equipment for the years ended December 31, 2016, 2015 and 2014 is set out below:

Year ended December 31,	2016	2015	2014
(millions of Canadian dollars)
Liquids Pipelines	3,956	5,882	8,911
Gas Distribution	713	858	610
Gas Pipelines and Processing	176	385	593
Green Power and Transmission	251	68	333
Energy Services	-	-	3
Eliminations and Other	32	80	74
Total capital expenditures	5,128	7,273	10,524

2016

·The timing of projects approval, construction and in-service dates impact 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 was 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 by the Company in 2016 for acquisitions. During the second quarter of 2016, the Company 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.

2015

·For the year ended December 31, 2015, additions to property, plant and equipment resulted in cash spending of $7,273 million compared with $10,524 million for the year ended December 31, 2014. As previously noted, the timing of growth projects’ approval, construction and in-service dates impact the timing of cash requirements. In 2014, higher capital additions reflected expenditures on significant growth projects brought into service, including Flanagan South, as well as ongoing expenditures on major components of the Eastern Access Program and Edmonton to Hardisty Expansion project, which were completed in 2015.

Financing Activities

2016

·The Company’s 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. The Company’s funding requirements are a reflection of the timing of various growth projects.

·In 2016, the Company’s 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 the Company’s common share issuance in March 2016, which were partly utilized to reduce the Company’s credit facilities and 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 higher number of common shares outstanding primarily as a result of the common share issuance noted above.

88

·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.

2015

·The Company’s financing requirements in 2015 were lower compared with the corresponding period and reflected lower capital requirements as a result of a combination of timing of capital expenditures and increased cash flow generation from operations. Additionally, during the first eight months of 2015, during the design and negotiation of the Canadian Restructuring Plan, the Company did not access the public capital markets as regularly as it had in previous years.

·In 2015, the Company increased its overall debt by $3,663 million compared with $9,000 million in 2014. The higher debt issuance in 2014 reflected greater financing needs in support of the Company’s growth program. Funding of the Company’s growth program was also achieved through the issuance of preference shares. In 2014, the Company issued $1,365 million of preference shares, whereas there were no preference shares issued in 2015. The overall increase in common shares and preference shares outstanding, along with an increase in the common share dividend rate, resulted in a higher amount of dividends paid by the Company in 2015 compared with 2014.

·Included within Financing Activities are contributions and distributions to noncontrolling interests. In 2015 the Company did not issue any preference shares or common shares through public offerings directly; however, through its affiliates mainly the Fund Group and EEP, the Company raised $1,285 million of net proceeds in equity capital. These contributions in 2015 were partially offset by distributions of $794 million to noncontrolling interests; whereas, in 2014, the Company made distributions, net of contributions, of $79 million to its noncontrolling interests.

89

Preference Share Issuances

Since July 2011, the Company has issued 290 million preference shares for gross proceeds of approximately $7,277 million with the following characteristics. See Outstanding Share Data.

					Per Share
					Base	Redemption	Right to
			Initial		Redemption	and Conversion	Convert
		Gross Proceeds	Yield	Dividend1	Value2	Option Date2,3	Into3,4
(Canadian dollars, unless otherwise stated)
Series B5		$500 million	4.00%	$1.00	$25	June 1, 2017	Series C
Series D5		$450 million	4.00%	$1.00	$25	March 1, 2018	Series E
Series F5		$500 million	4.00%	$1.00	$25	June 1, 2018	Series G
Series H5		$350 million	4.00%	$1.00	$25	September 1, 2018	Series I
Series J5		US$200 million	4.00%	US$1.00	US$25	June 1, 2017	Series K
Series L5		US$400 million	4.00%	US$1.00	US$25	September 1, 2017	Series M
Series N5		$450 million	4.00%	$1.00	$25	December 1, 2018	Series O
Series P5		$400 million	4.00%	$1.00	$25	March 1, 2019	Series Q
Series R5		$400 million	4.00%	$1.00	$25	June 1, 2019	Series S
Series 15		US$400 million	4.00%	US$1.00	US$25	June 1, 2018	Series 2
Series 35		$600 million	4.00%	$1.00	$25	September 1, 2019	Series 4
Series 55		US$200 million	4.40%	US$1.10	US$25	March 1, 2019	Series 6
Series 75		$250 million	4.40%	$1.10	$25	March 1, 2019	Series 8
Series 95		$275 million	4.40%	$1.10	$25	December 1, 2019	Series 10
Series 115		$500 million	4.40%	$1.10	$25	March 1, 2020	Series 12
Series 135		$350 million	4.40%	$1.10	$25	June 1, 2020	Series 14
Series 155		$275 million	4.40%	$1.10	$25	September 1, 2020	Series 16
Series 175		$750 million	5.15%	$1.29	$25	March 1, 2022	Series 18
1	The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board. With the exception of Series A Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15%. No other series of Preference Shares has this feature.
2	The Company may at its 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 the Conversion Option Date and every fifth anniversary thereafter.
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 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	For dividends declared, see Liquidity and Capital Resources – Sources and Uses of Cash – Dividend Reinvestment and Share Purchase Plan.

Common Share Issuances

On March 1, 2016, the Company completed the issuance of 56.5 million common shares for gross proceeds of approximately $2.3 billion, inclusive of the shares issued on exercise of the full amount of the underwriters’ over-allotment option to purchase an additional 7.4 million common shares. The proceeds were used to reduce short-term indebtedness pending reinvestment in capital projects and are expected to be sufficient to fulfill equity funding requirements for Enbridge’s current commercially secured growth program through the end of 2017 before consideration of the additional equity raised by ENF in April 2016.

On June 24, 2014, the Company completed the issuance of 7.9 million common shares for gross proceeds of approximately $400 million and on July 8, 2014, issued a further 1.2 million common shares pursuant to the underwriters’ over-allotment option for additional gross proceeds of approximately $60 million. The proceeds were used to fund the Company’s growth projects, reduce short-term indebtedness and for other general corporate purposes.

Dividend Reinvestment and Share Purchase Plan

Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends. For the year ended December 31, 2016, dividends declared were $1,945 million (2015 - $1,596 million), of which $1,150 million (2015 - $950 million) were paid in cash and reflected in financing activities. The remaining $795 million (2015 - $646 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the years ended December 31, 2016 and 2015, 40.9% and 40.5%, respectively, of total dividends declared were reinvested.

90

On January 5, 2017, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2017 to shareholders of record on February 15, 2017.

Common Shares	$0.58300
Preference Shares, Series A	$0.34375
Preference Shares, Series B	$0.25000
Preference Shares, Series D	$0.25000
Preference Shares, Series F	$0.25000
Preference Shares, Series H	$0.25000
Preference Shares, Series J	US  $0.25000
Preference Shares, Series L	US  $0.25000
Preference Shares, Series N	$0.25000
Preference Shares, Series P	$0.25000
Preference Shares, Series R	$0.25000
Preference Shares, Series 1	US  $0.25000
Preference Shares, Series 3	$0.25000
Preference Shares, Series 5	US  $0.27500
Preference Shares, Series 7	$0.27500
Preference Shares, Series 9	$0.27500
Preference Shares, Series 11	$0.27500
Preference Shares, Series 13	$0.27500
Preference Shares, Series 15	$0.27500
Preference Shares, Series 17	$0.34570

SPONSORED VEHICLES

The Company utilizes its sponsored vehicles to enhance its enterprise-wide funding program. The Company’s drop-down strategy, whereby Enbridge sells mature, stable assets generating reliable cash flows to its sponsored vehicles, involves monetizing assets with the objective of diversifying funding sources and maintaining access to low cost capital.

The Fund Group

In November 2014, Enbridge finalized an agreement to transfer natural gas and diluent pipeline interests to the Fund for a total consideration of $1.8 billion. For further details, refer to The Fund Group 2014 Drop Down Transaction. In September 2015, the Company completed the Canadian Restructuring Plan. For further details, refer to Canadian Restructuring Plan.

EEP

In the United States, the restructuring of EEP’s equity was completed in 2014 as discussed below. Further, in January 2015, Enbridge and EEP completed the drop down of Enbridge’s 66.7% interest in the United States segment of the Alberta Clipper Pipeline to EEP. Aggregate consideration for the transaction was US$1 billion, consisting of approximately US$694 million of Class E equity units issued to Enbridge by EEP and the repayment of approximately US$306 million of indebtedness owed to Enbridge. Refer to Liquids Pipelines – Lakehead System – Alberta Clipper Drop Down.

In May 2016, EEP announced that it was exploring various strategic alternatives for its investments in Midcoast Operating Partners, L.P. and MEP. On January 27, 2017, Enbridge announced that it had entered into a merger agreement through a wholly-owned subsidiary, whereby it will take private MEP by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US$170 million in the second quarter of 2017. For additional information on Enbridge’s on-going strategic review of EEP, refer to United States Sponsored Vehicle Strategy.

91

Economic Interest

Enbridge’s ownership interest in EEP is impacted by EEP’s issuance and sale of its Class A common units. To the extent Enbridge does not fully participate in these offerings, the Company’s economic interest in EEP is reduced. At December 31, 2016, Enbridge’s economic interest in EEP was 35.3% (2015 - 35.7%, 2014 - 33.7%). The Company’s average economic interest in EEP during 2016 was 35.5% (2015 - 36.0%, 2014 - 27.3%). Additionally, Enbridge also holds a US$1.2 billion investment in EEP preferred units as further described below under EEP Preferred Unit Private Placement.

Common Unit Issuance

In March 2015, EEP completed the issuance of eight million Class A common units for gross proceeds of approximately US$294 million before underwriting discounts and commissions and offering expenses. Enbridge did not participate in the issuance; however, the Company made a capital contribution of US$6 million to maintain its 2% GP interest in EEP. EEP used the proceeds from the offering to fund a portion of its capital expansion projects and for general partnership purposes.

Equity Restructuring

In June 2014, EEP and Enbridge announced an agreement to restructure EEP’s equity. Effective July 1, 2014, Enbridge Energy Company, Inc., a wholly-owned subsidiary of Enbridge and the GP of EEP, irrevocably waived its then existing IDR in excess of its 2% GP interest in exchange for 66.1 million Class D units and 1,000 Incentive Distribution Units (collectively, the Equity Restructuring). The GP share of incremental cash distributions decreased from 48% of all distributions in excess of US$0.4950 per unit per quarter down to 23% of all distributions in excess of EEP’s quarterly distribution of US$0.5435 per unit per quarter. The Class D units carry a distribution equal to the quarterly distribution on the Class A common units. The 2014 third and fourth quarter distributions on the Class D units were adjusted to provide Enbridge with an aggregate distribution in 2014 equal to the distribution on its IDR as if the Equity Restructuring had not occurred. The Incentive Distribution Units are not entitled to a distribution initially and in the event of any decrease in the Class A common unit distribution below US$0.5435 per unit in any quarter during the next five years, the distribution on the Class D units will be reduced to the amount which would have been received by Enbridge under the IDR as if the Equity Restructuring had not occurred.

The Class D units have a notional value per unit equivalent to the closing market price of the Class A common units on June 17, 2014 (Notional Value) and have the same voting rights as the Class A common units. The Class D units are convertible on a one-for-one basis into Class A common units at any time on or after the fifth anniversary of the closing date, at the holder’s option. In the event of a liquidation event (or any merger or other extraordinary transaction), the Class D unitholders will have a preference in liquidation equal to 20% of the Notional Value, with such preference being increased by an additional 20% on each anniversary of the closing date, resulting in a liquidation preference equal to 100% of the Notional Value on the fourth anniversary of the closing date. The Class D units will be redeemable after 30 years from issuance in whole or in part at EEP’s option for either a cash amount equal to the Notional Value per unit or newly issued Class A common units with an aggregate market value at redemption equal to 105% of the aggregate Notional Value of the Class D units being redeemed.

Distributions

In July 2014, EEP increased its quarterly distribution from US$0.5435 per unit to common unitholders to US$0.5550. On December 23, 2014, EEP announced it would increase its quarterly distribution to US$0.5700 per unit to common unitholders following the announcement that the Alberta Clipper Drop Down was finalized. Refer to Liquids Pipelines – Lakehead System – Alberta Clipper Drop Down. In July 2015, EEP further increased its quarterly distribution to US$0.5830.

In 2016, Enbridge received from EEP, incentive distributions of US$21 million (2015 - US$19 million, 2014 - US$39 million). Also in 2016, Enbridge received distributions of US$196 million from Class D units (2015 - US$195 million, 2014 - US$108 million) and Class E units which were issued under the Equity Restructuring and Alberta Clipper Drop Down transactions.

EEP Preferred Unit Private Placement

In 2013, Enbridge invested US$1.2 billion in preferred units of EEP to reduce the amount of near-term external funding required by EEP to fund its share of the Company’s organic growth program. On July 30, 2015, Enbridge and EEP reached an agreement to extend the deferral of quarterly cash distribution on these preferred units. The first quarterly cash distribution will now occur in the third quarter of 2018 and the deferred distribution will now be payable in equal amounts over a 12-quarter period beginning the first quarter of 2019.

92

CONTRACTUAL OBLIGATIONS

Payments due under contractual obligations over the next five years and thereafter are as follows:

			Less than			After
		Total	1 year	1-3 years	3-5 years	5 years
(millions of Canadian dollars)
Long-term debt1		31,967	2,599	3,036	4,714	21,618
Capital and operating leases2		987	118	145	130	594
Long-term contracts4		11,055	3,714	2,785	2,130	2,426
Pension obligations3		148	148	-	-	-
Total contractual obligations		44,157	6,579	5,966	6,974	24,638
1	Represents debenture and term note maturities and excludes interest obligations. Changes to the planned funding requirements are dependent on the terms of any debt refinancing agreements.
2	Includes land leases.
3	Assumes only required payments will be made into the pension plans in 2017. Contributions are made in accordance with independent actuarial valuations as at December 31, 2016. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.
4	Includes commitments for transportation service agreements totaling $618 million which assume a light to heavy crude oil ratio of 80:20 on certain pipelines and a power charge of $0.06 per barrel.

CAPITAL EXPENDITURE COMMITMENTS

Included within Long-term contracts in the table above are contracts that the Company has signed for the purchase of services, pipe and other materials totalling $1,903 million which are expected to be paid over the next five years.

TAX MATTERS

Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

OTHER LITIGATION

The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, Management believes that the resolution of such actions and proceedings will not have a material impact on the Company’s consolidated financial position or results of operations.

93

OUTSTANDING SHARE DATA1

PREFERENCE SHARES

		Redemption and	Right to
		Conversion	Convert
	Number	Option Date2,3	Into3
Preference Shares, Series A	5,000,000	-	-
Preference Shares, Series B	20,000,000	June 1, 2017	Series C
Preference Shares, Series D	18,000,000	March 1, 2018	Series E
Preference Shares, Series F	20,000,000	June 1, 2018	Series G
Preference Shares, Series H	14,000,000	September 1, 2018	Series I
Preference Shares, Series J	8,000,000	June 1, 2017	Series K
Preference Shares, Series L	16,000,000	September 1, 2017	Series M
Preference Shares, Series N	18,000,000	December 1, 2018	Series O
Preference Shares, Series P	16,000,000	March 1, 2019	Series Q
Preference Shares, Series R	16,000,000	June 1, 2019	Series S
Preference Shares, Series 1	16,000,000	June 1, 2018	Series 2
Preference Shares, Series 3	24,000,000	September 1, 2019	Series 4
Preference Shares, Series 5	8,000,000	March 1, 2019	Series 6
Preference Shares, Series 7	10,000,000	March 1, 2019	Series 8
Preference Shares, Series 9	11,000,000	December 1, 2019	Series 10
Preference Shares, Series 11	20,000,000	March 1, 2020	Series 12
Preference Shares, Series 13	14,000,000	June 1, 2020	Series 14
Preference Shares, Series 15	11,000,000	September 1, 2020	Series 16
Preference Shares, Series 17	30,000,000	March 1. 2022	Series 18

COMMON SHARES

		Number
Common Shares - issued and outstanding (voting equity shares)		943,186,589
Stock Options - issued and outstanding (20,738,364 vested)		35,751,751
1	Outstanding share data information is provided as at February 6, 2017.
2	All preference shares are non-voting equity shares. Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of Preference Shares, the Company may, at its 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, as discussed under the terms of the respective Preference Shares.

94

QUARTERLY FINANCIAL INFORMATION

2016	Q1		Q2		Q3		Q4	Total
(millions of Canadian dollars, except for per share amounts)
Revenues	8,795		7,939		8,488		9,338	34,560
Earnings/(loss) attributable to common shareholders	1,213		301		(103	)	365	1,776
Earnings/(loss) per common share	1.38		0.33		(0.11	)	0.39	1.95
Diluted earnings/(loss) per common share	1.38		0.33		(0.11	)	0.39	1.93
Dividends paid per common share	0.530		0.530		0.530		0.530	2.120
EGD - warmer/(colder) than normal weather1	13		(7	)	-		7	13
Changes in unrealized derivative fair value (gains)/loss1	(652	)	1		32		189	(430	)
2015	Q1		Q2		Q3		Q4	Total
(millions of Canadian dollars, except for per share amounts)
Revenues	7,929		8,631		8,320		8,914	33,794
Earnings/(loss) attributable to common shareholders	(383	)	577		(609	)	378	(37	)
Earnings/(loss) per common share	(0.46	)	0.68		(0.72	)	0.44	(0.04	)
Diluted earnings/(loss) per common share	(0.46	)	0.67		(0.72	)	0.44	(0.04	)
Dividends paid per common share	0.465		0.465		0.465		0.465	1.86
EGD - warmer/(colder) than normal weather1	(33	)	6		-		16	(11	)
Changes in unrealized derivative fair value (gains)/loss1	977		(296	)	654		45	1,380

1Included in earnings/(loss) attributable to common shareholders.

Several factors impact comparability of the Company’s financial results on a quarterly basis, including, but not limited to, seasonality in the Company’s gas distribution businesses, fluctuations in market prices such as foreign exchange rates and commodity prices, disposals of investments or assets and the timing of in-service dates of new projects.

A significant part of the Company’s revenues are generated from its energy services operations. Revenues from these operations depend on activity levels, which vary from year to year depending on market conditions and commodity prices. Commodity prices do not directly impact earnings since these earnings reflect a margin or percentage of revenues that depends more on differences in commodity prices between locations and points in time than on the absolute level of prices.

EGD and the Company’s other gas distribution businesses are subject to seasonal demand. A significant portion of gas distribution customers use natural gas for space heating; therefore, volumes delivered and resulting revenues and earnings typically increase during the winter months of the first and fourth quarters of any given year. Revenues generated by EGD and other gas distribution businesses also vary from quarter-to-quarter with fluctuations in the price of natural gas, although earnings remain neutral due to the flow-through nature of these costs.

The Company actively manages its exposure to market risks including, but not limited to, commodity prices, interest rates and foreign exchange rates. To the extent derivative instruments used to manage these risks are non-qualifying for the purposes of applying hedge accounting, changes in unrealized fair value gains and losses on these instruments will impact earnings.

In addition to the impacts of weather in EGD’s franchise area and changes in unrealized gains and losses outlined above, significant items impacting the consolidated quarterly earnings are noted below:

·Included in the fourth quarter of 2016 was a gain of $520 million (after-tax attributable to Enbridge) on the disposal of South Prairie Region assets within the Liquids Pipelines segment.

·Included in the fourth quarter of 2016 was an asset impairment charge of $272 million (after-tax attributable to Enbridge) related to Northern Gateway. For additional information, refer to Other Announced Projects Under Development – Liquids Pipelines – Northern Gateway Project.

95

·Included in the fourth quarter of 2016 were employee severance and restructuring costs incurred in relation to the Company’s Building Our Energy Future initiative, with a net charge of $37 million to earnings. For additional information, refer to Corporate Vision and Strategy – Strategy – Maintain the Foundation – Attract, Retain and Develop Highly Capable People.

·Included in the fourth quarter of 2016 and second quarter of 2015 were the tax impacts of asset transfers between entities under common control of Enbridge. The intercompany gains realized by the selling entities have been eliminated from the Company’s consolidated financial statements. However, as the transaction involved sale of partnership units, the tax consequences remained in consolidated earnings and resulted in charges of $11 million and $39 million, respectively.

·In the third quarter of 2016, impairment charges of $1,000 million ($81 million after-tax attributable to Enbridge), including related project costs of $8 million, were recognized in relation to EEP’s Sandpiper Project as discussed in Growth Projects – Commercially Secured Projects – Liquids Pipelines – Sandpiper Project (EEP). In the fourth quarter of 2016, additional project costs of $4 million (nil after-tax attributable to Enbridge) were recognized.

·Included in the second and third quarters of 2016 were after-tax costs attributable to Enbridge of $12 million and $10 million, respectively, incurred in relation to the restart of certain of Enbridge’s pipelines and facilities following the northeastern Alberta wildfires.

·Included in the second quarter of 2016 were impairment charges of $103 million (after-tax attributable to Enbridge) related to Enbridge’s 75% joint venture interest in Eddystone Rail, attributable to market conditions which impacted volumes at the rail facility.

·Included in earnings are after-tax insurance recoveries associated with the Line 37 crude oil release which occurred in June 2013. Insurance recoveries of $3 million were recognized in the first quarter of 2016, and $9 million and $13 million were recognized in each of the first and fourth quarters of 2015, respectively. Earnings also reflected after-tax costs of $6 million in the second quarter of 2015 in connection with the Line 37 crude oil release.

·Included in the fourth quarter of 2015 were employee severance costs in relation to the Company’s enterprise-wide reduction of workforce, with a net charge of $25 million to earnings.

·Included in the fourth quarter of 2015 was an asset impairment charge of US$63 million ($11 million after-tax attributable to Enbridge) related to EEP’s Berthold rail facility due to the inability to renew committed shipper agreements beyond 2016 or secure sufficient spot volume.

·Included in the third quarter of 2015 were impacts from the transfer of assets between entities under common control of Enbridge in connection with the transfer of Enbridge’s Canadian Liquids Pipelines business and certain Canadian renewable energy assets to EIPLP in which the Fund has an indirect interest, resulting in a $247 million loss on the de-designation of interest rate hedges, an $88 million write-off of a regulatory asset in respect of taxes and $16 million of transaction costs.

·Included in the third quarter of 2015 was an after-tax gain of $44 million on the disposal of non-core assets within the Liquids Pipelines segment.

·Included in the second quarter of 2015 was a goodwill impairment charge of $440 million ($167 million after-tax attributable to Enbridge) related to EEP’s natural gas and NGL businesses due to a prolonged decline in commodity prices which reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL systems.

Finally, the Company is in the midst of a substantial growth capital program and the timing of construction and completion of growth projects may impact the comparability of quarterly results. The Company’s capital expansion initiatives, including construction commencement and in-service dates, are described under Growth Projects – Commercially Secured Projects.

RELATED PARTY TRANSACTIONS

Other than the drop down transactions between Enbridge and its sponsored vehicles, including the Canadian Restructuring Plan and the transactions under the United States Sponsored Vehicle strategy, all related party transactions are conducted in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

96

Vector, a joint venture, contracts the services of Enbridge to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, were $7 million for the year ended December 31, 2016 (2015 - $7 million; 2014 - $7 million).

Certain wholly-owned subsidiaries within the Liquids Pipelines, Gas Distribution, Gas Pipelines and Processing and Energy Services segments have committed and uncommitted transportation arrangements with several joint venture affiliates that are accounted for using the equity method. Total amounts charged to the Company for transportation services for the year ended December 31, 2016 were $357 million (2015 - $332 million; 2014 - $256 million).

A wholly-owned subsidiary within Liquids Pipelines had a lease arrangement with a joint venture affiliate. During the year ended December 31, 2016, expenses related to the lease arrangement totalled $287 million (2015 - $151 million; 2014 - $21 million) and were recorded to Operating and administrative expense.

Certain wholly-owned subsidiaries within Gas Distribution and Energy Services segments made natural gas and NGL purchases of $98 million (2015 - $228 million; 2014 - $315 million) from several joint venture affiliates during the year ended December 31, 2016.

Natural gas sales of $49 million (2015 - $5 million; 2014 - $58 million) were made by certain wholly-owned subsidiaries within the Energy Services segment to several joint venture affiliates during the year ended December 31, 2016.

LONG-TERM NOTES RECEIVABLE FROM AFFILIATES

Amounts receivable from affiliates include a series of loans to Vector and other affiliates totalling $130 million and $140 million, respectively (2015 - $149 million and $3 million, respectively), which require quarterly interest payments at annual interest rates ranging from 4% to 12%. These amounts are included in Deferred amounts and other assets.

INTERCOMPANY ACCOUNTS RECEIVABLE SALE

In 2013, certain of EEP’s subsidiaries entered into a Receivables Purchase Agreement (the Receivables Agreement) with a wholly-owned subsidiary of Enbridge, whereby Enbridge would purchase on a monthly basis certain trade and accrued receivables of such subsidiaries through December 2016. The Receivables Agreement was amended in June 2016 to extend the termination date that provides for purchases to occur on a monthly basis through to December 2019 provided accumulated purchases net of collections do not exceed US$450 million at any one point. The primary objective of the accounts receivable transaction is to further enhance EEP’s available liquidity and its cash available from operations for payment of distributions during the next few years until EEP’s large growth capital commitments are permanently funded, as well as to provide an annual saving in EEP’s cost of funding during this period.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

The Company’s earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price (collectively, market risk). Formal risk management policies, processes and systems have been designed to mitigate these risks.

The following summarizes the types of market risks to which the Company is exposed and the risk management instruments used to mitigate them. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.

Foreign Exchange Risk

The Company generates certain revenues, incurs expenses, and holds a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, the Company’s earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.

97

The Company has implemented a policy whereby, at a minimum, it hedges a level of foreign currency denominated earnings exposures over a five year forecast horizon. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. The Company hedges certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt.

Interest Rate Risk

The Company’s earnings and cash flows are exposed to short term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.4%.

The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.7%.

The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt within its Board of Directors approved policy limit of a maximum of 25% floating rate debt as a percentage of total debt outstanding. The Company primarily uses qualifying derivative instruments to manage interest rate risk.

Commodity Price Risk

The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of its ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. The Company employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk.

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, Restricted Stock Units. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

98

The Effect of Derivative Instruments on the CONSOLIDATED Statements of Earnings and Comprehensive Income

The following table presents the effect of cash flow hedges and net investment hedges on the Company’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes.

Year ended December 31,	2016		2015		2014
(millions of Canadian dollars)
Amount of unrealized gains/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	(19	)	77		8
Interest rate contracts	(90	)	(275	)	(1,086	)
Commodity contracts	14		9		50
Other contracts	39		(47	)	13
Net investment hedges
Foreign exchange contracts	22		(248	)	(113	)
	(34	)	(484	)	(1,128	)
Amount of (gains)/loss reclassified from accumulated other comprehensive income (AOCI) to earnings (effective portion)
Foreign exchange contracts1	2		9		8
Interest rate contracts2	145		128		101
Commodity contracts3	(12	)	(46	)	4
Other contracts4	(29	)	28		(7	)
	106		119		106
De-designation of qualifying hedges in connection with the Canadian Restructuring Plan
Interest rate contracts2	-		338		-
	-		338		-
Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)
Interest rate contracts2	61		21		216
Commodity contracts3	-		5		(6	)
	61		26		210
Amount of gains/(loss) from non-qualifying derivatives included in earnings
Foreign exchange contracts1	935		(2,187	)	(936	)
Interest rate contracts2	73		(363	)	4
Commodity contracts3	(508	)	199		1,031
Other contracts4	9		(22	)	7
	509		(2,373	)	106

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

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

3Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

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

LIQUIDITY RISK

Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees, as they become due. In order to manage this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintains substantial capacity under its committed bank lines of credit, as discussed under Liquidity and Capital Resources, to address any contingencies. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. The Company also maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. The Company is in compliance with all the terms and conditions of its committed credit facilities as at December 31, 2016. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities.

99

CREDIT RISK

Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, the Company enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through credit exposure limits and contractual requirements, netting arrangements and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.

The Company generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with the counterparties in these particular circumstances.

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Gas Distribution, credit risk is mitigated by the utilities’ large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

FAIR VALUE MEASUREMENTS

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

GENERAL BUSINESS RISKS

Strategic and Commercial Risks

Economic Regulation, Permits and Approvals

Many of the Company’s operations are regulated. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States have changed significantly in past years and there is no assurance that further substantial changes will not occur.

The Company also faces economic regulation, permits and approvals risk, which broadly defined, is the risk that regulators or other government entities change or reject proposed or existing commercial arrangements including permits and regulatory approvals for new projects, such as the Merger Transaction and the Company’s L3R Program. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on the Company’s revenues and earnings. Increasing regulatory scrutiny and resulting delays in regulatory permits and approvals with respect to projects could result in cost escalations, construction delays and in-service delays which also negatively impact the Company’s operations.

The FERC continues to intensify its oversight of financial reporting, risk standards and affiliate rules, and in 2014, the Pipeline and Hazardous Materials Safety Administration issued new pipeline standards and regulations on managing gas pipeline integrity. The Company continues ongoing dialogue with regulatory agencies and participates in industry groups to ensure it is informed of emerging issues in a timely manner.

100

The Company believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of its operations. The Company also involves its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations, as well as in the establishment of tariffs and tolls for these assets. Enbridge retains dedicated professional staff and maintains strong relationships with customers, intervenors and regulators to help minimize economic regulation risk. However, despite the efforts of the Company to mitigate economic regulation risk, there remains a risk that a regulator could overturn long-term agreements between the Company and shippers or deny the approval and permits for new projects.

Project Execution

As the Company continues to execute on a large slate of commercially secured growth projects, it continues to focus on completing projects safely, on-time and on-budget. The Company’s ability to successfully execute the development of its organic growth projects may be influenced by capital constraints, third-party opposition, changes in shipper support over time, delays in or changes to government and regulatory approvals, cost escalations, construction delays, inadequate resources, in-service delays and increasing complexity of projects (collectively, Execution Risk).

Early stage project risks include right-of-way procurement, special interest group opposition, Crown consultation and environmental and regulatory permitting. Cost escalations or missed in-service dates on future projects may impact future earnings and cash flows and may hinder the Company’s ability to secure future projects. Construction delays due to regulatory delays, third-party opposition, contractor or supplier non-performance and weather conditions may impact project development.

The Company strives to be an industry leader in project execution and through its Major Projects Group, it seeks to mitigate project execution risk. The Major Projects Group is centralized and has a clearly defined governance structure and process for all major projects, with dedicated resources organized to lead and execute each major project.

Capital constraints and cost escalation risks are mitigated through structuring of commercial agreements, typically where shippers retain complete or a share of capital cost excess. Detailed cost tracking and centralized purchasing is used on all major projects to facilitate optimum pricing and service terms. Strategic relationships have been developed with suppliers and contractors and those selected are chosen based on the Company’s strict adherence to safety including robust safety standards embedded in contracts with suppliers. The Company has assessed work volumes for the next several years across its major projects to optimize the expected costs, supply of services, material and labour to execute the projects. Underpinning this approach is Major Project’s Project Lifecycle Gating Control tool which helps to ensure that schedule, cost, safety and quality objectives are on track and met for each stage of a project’s development and construction.

Consultations with regulators are held in-advance of project construction to enhance understanding of project rationale and ensure applications are compliant and robust, while at all times maintaining a strong focus on integrity and public safety. The Company also actively involves its legal and regulatory teams to work closely with the Major Projects Group to engage in open dialogue with government agencies, regulators, land owners, Indigenous peoples and special interest groups to identify and develop appropriate responses to their concerns regarding the Company’s projects.

Public Opinion

Public opinion or reputation risk is the risk of negative impacts on the Company’s business, operations or financial condition resulting from changes in the Company’s reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups’ negative portrayal of the industry in which Enbridge operates as well as their opposition to development projects, such as the Bakken Pipeline System. Potential impacts of a negative public opinion may include loss of business, delays in project execution, legal action, increased regulatory oversight or delays in regulatory approval and higher costs.

101

Reputation risk often arises as a consequence of some other risk event, such as in connection with operational, regulatory or legal risks. Therefore, reputation risk cannot be managed in isolation from other risks. The Company manages reputation risk by:

·having health, safety and environment management systems in place, as well as policies, programs and practices for conducting safe and environmentally sound operations with an emphasis on the prevention of any incidents;

·having formal risk management policies, procedures and systems in place to identify, assess and mitigate risks to the Company;

·operating to the highest ethical standards, with integrity, honesty and transparency, and maintaining positive relationships with customers, investors, employees, partners, regulators and other stakeholders;

·building awareness and understanding of the role energy and Enbridge play in people’s lives in order to promote better understanding of the Company and its businesses;

·having strong corporate governance practices, including a Statement on Business Conduct, which requires all employees to certify their compliance with Company policy on an annual basis, and whistleblower procedures, which allow employees to report suspected ethical concerns on a confidential and anonymous basis; and

·pursuing socially responsible operations as a longer-term corporate strategy (implemented through the Company’s CSR Policy, Climate Policy and Indigenous Peoples Policy). For further discussion on this strategy, refer to Corporate Vision and Strategy – Strategy – Maintain the Foundation – Maintain the Company’s Social License to Operate.

The Company’s actions noted above are the key mitigation actions against negative public opinion; however, the public opinion risk cannot be mitigated solely by the Company’s individual actions. The Company actively works with other stakeholders in the industry to collaborate and work closely with government and Indigenous Peoples communities to enhance the public opinion of the Company, as well as the industry in which it operates. Unless otherwise specifically stated, none of the content of the policies or initiatives described above are incorporated by reference herein.

Transformation Projects

Transformation projects risk is the risk that a large change management initiative carried out by the Company will fail to fully deliver anticipated results because of a failure by the Company to fully address risks associated with change delivery and implementation. This could result in negative financial, operational and reputational impacts to the Company. Such large scale change management initiatives include the Merger Transaction and Enbridge’s Building Our Energy Future initiative. With respect to the Merger Transaction, Enbridge and Spectra Energy have established a joint integration planning team that is laying the foundation for the efficient integration of the two companies once the Merger Transaction closes and to help ensure that anticipated operating synergies are achieved. For further discussion on the Merger Transaction, refer to Merger Agreement with Spectra Energy. In 2016, Enbridge also launched the Building Our Energy Future initiative, an enterprise-wide transformation program that is intended to drive out focused improvements across the enterprise to ensure an effective and efficient organization that will better support the execution of key strategies, such as the above noted Enbridge and Spectra Energy integration. To mitigate its transformation projects risk associated with the Building Our Energy Future initiative, Enbridge established the Results Delivery Office to manage the integrated plan and roadmap of initiatives, execute the transformation process, provide coaching and support to impacted teams in the areas of results delivery, tracking progress and identification of new risks and establishment of appropriate mitigation steps to address those risks.

Planning and Investment Analysis

The Company evaluates expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, change in cost estimates, project scoping and risk assessment could result in a loss in profits for the Company. Large scale acquisitions such as the Merger Transaction, may involve significant integration risk as discussed above under Transformation Projects and under Merger Agreement with Spectra Energy.

102

The planning and investment analysis process involves all levels of management and Board of Directors’ review to ensure alignment across the Company. A centralized corporate development group rigorously evaluates all major investment proposals using consistent due diligence processes, including a thorough review of the asset quality, systems and projected financial performance of the assets being assessed.

Environmental and Safety Risks

Public, Worker and Contractor Safety

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

Safety and operational reliability are the most important priorities at Enbridge. Enbridge’s mitigation efforts to reduce the likelihood and severity of a public safety incident are executed primarily through its ORM Plan and emergency response preparedness, as described below in Environmental Incident. The Company also actively engages stakeholders through public safety awareness activities to ensure the public is aware of potential hazards and understands the appropriate actions to take in the event of an emergency. Enbridge also actively engages first responders through education programs that endeavour to equip first responders with the skills and tools to safely and effectively respond to a potential incident.

Finally, Enbridge believes in a safety culture where safety incidents are not tolerated by employees and contractors and has established a target of zero incidents. For employees, safety objectives have been incorporated across all levels of the Company and are included as part of an employee’s compensation measures. Contractors are chosen following a rigorous selection process that includes a strict adherence to Enbridge’s safety culture.

Environmental Incident

An environmental incident could have lasting reputational impacts to Enbridge and could impact its ability to work with various stakeholders. In addition to the cost of remediation activities (to the extent not covered by insurance), environmental incidents may lead to an increased cost of operating and insuring the Company’s assets, thereby negatively impacting earnings. The Company mitigates risk of environmental incidents through its ORM Plan, which broadly aims to position Enbridge as the industry leader for system integrity, environmental and safety programs. Mitigation efforts continue to focus on reducing the likelihood of an environmental incident. Under the umbrella of the ORM Plan the Company has continued its maintenance, excavation and repair program which is supported by operating and capital budgets for pipeline integrity. The Company’s $7.5 billion L3R Program, the largest project in the Company’s history, is a further commitment by the Company to its key strategic priority of safety and operational reliability. Once it is completed, the L3R Program will provide a major enhancement to Enbridge’s mainline system by replacing most segments of the Line 3 pipeline with the latest high-strength steel and coating.

Although the Company believes its integrated management system, plans and processes mitigate the risk of environmental incidents, there remains a chance that an environmental incident could occur. The ORM Plan also seeks to mitigate the severity of a potential environmental incident through continued process improvements, regular inspections and monitoring of facilities, as well as enhancements in leak detection processes and alarm analysis procedures. The Company has also invested significant resources to enhance its emergency response plans, operator training and landowner education programs to address any potential environmental incident.

The Company maintains comprehensive insurance coverage for its subsidiaries and affiliates that it renews annually. The insurance program includes coverage for commercial liability that is considered customary for its industry and includes coverage for environmental incidents excluding costs for fines and penalties. In the unlikely event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among Enbridge entities on an equitable basis based on an insurance allocation agreement among Enbridge and its subsidiaries and associated entities.

103

Natural Disaster Incident Risk

Enbridge is exposed to the risk of natural disaster incidents across many of its businesses. Natural disaster events include floods, earthquakes, droughts, wildfires, lightning strikes, wind storms, ice storms, hail storms, tornadoes and mudslides. Recent wildfires in Alberta and their adverse consequences for oil sands operations demonstrate the potential nature and extent of natural disaster incident risk for Enbridge.

Across various businesses, risk treatment measures include construction techniques to limit exposure to natural disaster risk, emergency preparedness plans, business continuity plans, emergency response exercises and insurance in high consequence locations. The Company has made considerable investments in emergency response equipment, training, and additional resources. Insurance coverage also provides protection from loss or damage to Enbridge assets resulting from most natural disaster events.

Information Technology Security or Systems Incident

The Company’s infrastructure, applications and data continue to become more integrated, creating an increased risk that failure in one system could lead to a failure of another system. There is also increasing industry-wide cyber-attacking activity targeting industrial control systems and intellectual property. A successful cyber-attack could lead to unavailability, disruption or loss of key functionalities within the Company’s industrial control systems which could impact pipeline operations and potentially result in an environmental or public safety incident. A successful cyber-attack could also lead to a large scale data breach resulting in unauthorized disclosure, corruption or loss of sensitive company or customer information which could have lasting reputational impacts to Enbridge and could impact its ability to work with various stakeholders.

The Company has implemented a comprehensive security strategy that includes a security policy and standards framework, defined governance and oversight, layered access controls, continuous monitoring, infrastructure and network security, threat detection and incident response through a security operations centre. The Company’s security strategy also includes continuing to improve overall intelligence levels related to cyber threat by partnering with a number of external law enforcement agencies and other organizations within its industry.

Service Interruption Incident

A service interruption due to a major power disruption or curtailment on commodity supply could have a significant impact on the Company’s ability to operate its assets and negatively impact future earnings, relationships with stakeholders and the Company’s reputation. Specifically, for Gas Distribution, any prolonged interruptions would ultimately impact gas distribution customers. Service interruptions that impact the Company’s crude oil transportation services can negatively impact shippers’ operations and earnings as they are dependent on Enbridge services to move their product to market or fulfill their own contractual arrangements. The Company mitigates service interruption risk through its diversified sources of supply, storage withdrawal flexibility, backup power systems, critical parts inventory and redundancies for critical equipment. Specifically for Gas Distribution, the GTA project, which was completed in March 2016, is a key mitigation as the project provides significant diversification of gas supply to EGD’s distribution network and will further reduce the likelihood of a service interruption incident.

Business Environment Risks

Indigenous Peoples Relations

Canadian judicial decisions have recognized that Indigenous peoples’ rights and treaty rights exist in proximity to the Company’s operations and future project developments. The courts have also confirmed that the Crown has a duty to consult with Indigenous peoples when its decisions or actions may adversely affect Indigenous peoples’ rights and interests or treaty rights. Crown consultation has the potential to delay regulatory approval processes and construction, which may affect project economics. In some cases, respecting Indigenous peoples’ rights may mean regulatory approval is denied or the conditions in the approval make a project economically challenging.

104

Given this environment and the breadth of relationships across the Company’s geographic span, Enbridge has implemented an Indigenous Peoples Policy. This policy promotes the achievement of participative and mutually beneficial relationships with Indigenous peoples affected by the Company’s projects and operations. Specifically, the policy sets out principles governing the Company’s relationships with Indigenous peoples and makes commitments to work with Indigenous peoples so they may realize benefits from the Company’s projects and operations. Notwithstanding the Company’s efforts to this end, the issues are complex and the impact of Indigenous peoples’ relations on Enbridge’s operations and development initiatives is uncertain. Unless otherwise specifically stated, none of the content of this policy is incorporated by reference herein, or otherwise part of, this MD&A.

Special Interest Groups including Non-Governmental Organizations

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

The Company works proactively with special interest groups and non-governmental organizations to identify and develop appropriate responses to their concerns regarding its projects. The Company is investing significant resources in these areas. Its CSR program also reports on the Company’s responsiveness to environmental and community issues. Refer to Enbridge’s annual CSR Report, available online at http://csr.enbridge.com for further details regarding the CSR program. Unless otherwise specifically stated, none of the information contained on, or connected to, the Enbridge website is incorporated by reference in, or otherwise part of, this MD&A.

CRITICAL ACCOUNTING ESTIMATES

The following critical accounting estimates discussed below have an impact across the various segments of the Company.

DEPRECIATION

Depreciation of property, plant and equipment, the Company’s largest asset with a net book value at December 31, 2016 of $64,284 million (2015 - $64,434 million), or 75% of total assets, is provided following two primary methods. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated depreciation.

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

ASSET IMPAIRMENT

The Company evaluates the recoverability of its property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal or regulatory changes, or other factors indicate it may not recover the carrying amount of the assets. The Company continually monitors its businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. An impairment loss is recognized when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires the use of projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes to these projections and assumptions could result in revisions to the evaluation of the recoverability of the property, plant and equipment and the recognition of an impairment loss in the Consolidated Statements of Earnings.

105

The Company also tests goodwill for impairment annually or more frequently if events or changes in circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value. For the purposes of impairment testing, reporting units are identified as business operations within an operating segment. The Company has the option to first assess qualitative factors to determine whether it is necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test is performed, the first step involves determining the fair value of the Company’s reporting units inclusive of goodwill and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured as the excess of the carrying amount of the reporting unit’s allocated goodwill over the implied fair value of the goodwill based on the fair value of the reporting unit’s assets and liabilities.

REGULATORY ASSETS AND LIABILITIES

Certain of the Company’s businesses are subject to regulation by various authorities, including but not limited to, the NEB, the FERC, the Alberta Energy Regulator, the EUB and the OEB. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non-rate-regulated entities.

Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative (LMCI). Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if the Company identifies an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, the Company would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. As at December 31, 2016, the Company’s significant regulatory assets totalled $1,865 million (2015 - $1,782 million) and significant regulatory liabilities totalled $844 million (2015 - $869 million).

POSTRETIREMENT BENEFITS

The Company maintains pension plans, which provide defined benefit and/or defined contribution pension benefits and other postretirement benefits (OPEB) to eligible retirees. Pension costs and obligations for the defined benefit pension plans are determined using actuarial methods and are funded through contributions determined using the projected benefit method, which incorporates management’s best estimates of future salary level, other cost escalations, retirement ages of employees and other actuarial factors including discount rates and mortality. The Company determines discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments the Company anticipates making under each of the respective plans. These assumptions are reviewed annually by the Company’s actuaries. Actual results that differ from assumptions are amortized over future periods and therefore could materially affect the expense recognized and the recorded obligation in future periods. The actual return on plan assets exceeded the expectation by $19 million for the year ended December 31, 2016 (2015 - $62 million shortfall) as disclosed in Note 26, Retirement and Postretirement Benefits, to the 2016 Annual Consolidated Financial Statements. The difference between the actual and expected return on plan assets is amortized over the remaining service period of the active employees.

106

The following sensitivity analysis identifies the impact on the December 31, 2016 Consolidated Financial Statements of a 0.5% change in key pension and OPEB assumptions.

	Pension Benefits				OPEB
	Obligation		Expense		Obligation	Expense
(millions of Canadian dollars)
Decrease in discount rate	241		28		24	2
Decrease in expected return on assets	-		11		-	1
Decrease in rate of salary increase	(52	)	(12	)	-	-

CONTINGENT LIABILITIES

Provisions for claims filed against the Company are determined on a case-by-case basis. Case estimates are reviewed on a regular basis and are updated as new information is received. The process of evaluating claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the final determination of which could have a material impact on the financial results of the Company and certain of the Company’s subsidiaries and investments are detailed in Note 31, Commitments and Contingencies, of the 2016 Annual Consolidated Financial Statements. In addition, any unasserted claims that later may become evident could have a material impact on the financial results of the Company and certain of the Company’s subsidiaries and investments.

ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. The Company’s estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements.

Currently, for the majority of the Company’s assets, there is insufficient data or information to reasonably determine the timing of settlement for estimating the fair value of the ARO. In these cases, the ARO cost is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset.

In 2009, the NEB issued a decision related to the LMCI, which required holders of an authorization to operate a pipeline under the NEB Act to file a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The NEB’s decision stated that while pipeline companies are ultimately responsible for the full costs of abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable from the users of the pipeline upon approval by the NEB.

Following the NEB’s final approval of the collection mechanism and the set-aside mechanism for LMCI, the Company began collecting and setting aside funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trust in accordance with the NEB decision. The funds collected from shippers are reported within Transportation and other services revenues and Restricted long-term investments. Concurrently, the Company reflects the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities.

CHANGES IN ACCOUNTING POLICIES

ADOPTION OF NEW STANDARDS

Classification of Deferred Taxes on the Statements of Financial Position

Effective January 1, 2016, the Company elected to early adopt Accounting Standards Update (ASU) 2015-17 and applied the standard on a prospective basis. The amendments require that deferred tax liabilities and assets be classified as noncurrent in the Consolidated Statements of Financial Position.

107

The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations

Effective January 1, 2016, the Company adopted ASU 2015-16 on a prospective basis. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

Measurement Date of Defined Benefit Obligation and Plan Assets

Effective January 1, 2016, the Company adopted ASU 2015-04 on a prospective basis. The revised criteria simplify the fair value measurement of defined benefit plan assets and obligations. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

Simplifying the Presentation of Debt Issuance Costs

Effective January 1, 2016, the Company adopted ASU 2015-03 on a retrospective basis which, as at December 31, 2015, resulted in a decrease in Deferred amounts and other assets of $149 million and a corresponding decrease in Long-term debt of $149 million. The new standard requires debt issuance costs related to a recognized debt liability to be presented in the Consolidated Statements of Financial Position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. ASU 2015-15 was adopted in conjunction with the above standard and did not have a material impact on the Company’s consolidated financial statements. ASU 2015-15 clarifies the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit.

Amendments to the Consolidation Analysis

Effective January 1, 2016, the Company adopted ASU 2015-02 on a modified retrospective basis, which amended and clarified the guidance on variable interest entities (VIEs). There was a significant change in the assessment of limited partnerships and other similar legal entities as VIEs, including the removal of the presumption that the general partner should consolidate a limited partnership. As a result, the Company has determined that a majority of the limited partnerships that are currently consolidated or equity accounted for are VIEs. The amended guidance did not impact the Company’s accounting treatment of such entities, however, material disclosures for VIEs have been provided, as necessary.

Hybrid Financial Instruments Issued in the Form of a Share

Effective January 1, 2016, the Company adopted ASU 2014-16 on a modified retrospective basis. The revised criteria eliminate the use of different methods in practice in the accounting for hybrid financial instruments issued in the form of a share. The new standard clarifies the evaluation of the economic characteristics and risks of a host contract in these hybrid financial instruments. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

Development Stage Entities

Effective January 1, 2016, the Company adopted ASU 2014-10 on a retrospective basis. The new standard amends the consolidation guidance to eliminate the development stage entity relief when applying the VIE model and evaluating the sufficiency of equity at risk. The adoption of the pronouncement did not have a material impact on the Company’s consolidated financial statements.

FUTURE ACCOUNTING POLICY CHANGES

Clarifying the Definition of a Business in an Acquisition

ASU 2017-01 was issued in January 2017 with the intent of clarifying the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) of assets or businesses. The Company is currently assessing the impact of the new standard on the consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2017 and is to be applied on a prospective basis.

108

Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows

ASU 2016-18 was issued in November 2016 with the intent to add or clarify guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the cash flow statement. The amendments require that changes in restricted cash and restricted cash equivalents should be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017 and is to be applied on a retrospective basis.

Accounting for Intra-Entity Asset Transfers

ASU 2016-16 was issued in October 2016 with the intent of improving the accounting for the income tax consequences of intra-entity asset transfers other than inventory. Under the new guidance, an entity should recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. The accounting update is effective for annual and interim periods beginning on or after December 15, 2017 and is to be applied on a modified retrospective basis, with early adoption permitted. Effective January 1, 2017, the Company elected to early adopt ASU 2016-16. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements.

Simplifying Cash Flow Classification

ASU 2016-15 was issued in August 2016 with the intent of reducing diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statements of Cash Flows. The new guidance addresses eight specific presentation issues. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2017 and is to be applied on a retrospective basis.

Accounting for Credit Losses

ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The amendment adds a new impairment model, known as the current expected credit loss model that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019.

Improvements to Employee Share-Based Payment Accounting

ASU 2016-09 was issued in March 2016 with the intent of simplifying and improving several aspects of accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the Consolidated Statements of Cash Flows. The accounting update is effective for annual and interim periods beginning on or after December 15, 2016 and is to be applied on a prospective or retrospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements.

Recognition of Leases

ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the Consolidated Statements of Financial Position and disclosing additional key information about leasing arrangements. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018, and is to be applied using a modified retrospective approach.

109

Recognition and Measurement of Financial Assets and Liabilities

ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation, and disclosure of financial assets and liabilities. The amendments revise accounting related to the classification and measurement of investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value, and the disclosure requirements associated with the fair value of financial instruments. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017, and is to be applied by means of a cumulative-effect adjustment to the Statements of Financial Position as of the beginning of the fiscal year of adoption, with amendments related to equity securities without readily determinable fair values to be applied prospectively.

Revenue from Contracts with Customers

ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective January 1, 2018. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. The Company is currently assessing which transition method to use.

The Company has reviewed a sample of its revenue contracts in order to evaluate the effect of the new standard on its revenue recognition practices. Based on the Company’s initial assessment, the application of the standard may result in 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 would be reflected as a reduction of revenue. Additionally, estimates of variable consideration which will be required under the new standard for certain Liquids Pipelines, Gas Pipelines and Processing 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. While the Company has not yet completed the assessment, the Company’s preliminary view is that it does not expect these changes will have a material impact on revenue or earnings (loss). The Company is also developing processes to generate the disclosures required under the new standard.

CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and United States securities law. As at December 31, 2016, an evaluation was carried out under the supervision of and with the participation of Enbridge’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of Enbridge’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by Enbridge in reports that it files with or submits to the Securities and Exchange Commission (SEC) and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

Management’s Report on Internal Control over Financial Reporting

Management of Enbridge is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in the rules of the SEC and the Canadian Securities Administrators. The Company’s internal control over financial reporting is a process designed under the supervision and with the participation of executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with U.S. GAAP.

110

The Company’s internal control over financial reporting includes policies and procedures that:

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

·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 the Company’s assets that could have a material effect on the financial statements.

The Company’s internal control over financial reporting may not prevent or detect all misstatements because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the Company’s policies and procedures.

Management assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2016, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management concluded that the Company maintained effective internal control over financial reporting as at December 31, 2016.

During the year ended December 31, 2016, there has been no material change in the Company’s internal control over financial reporting.

The effectiveness of the Company’s internal control over financial reporting as at December 31, 2016 has been audited by PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company.

111