MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (MD&A) dated February 19, 2016 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, 2015, 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.

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 nearly 2,800 megawatts (MW) (2,000 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 nearly 11,000 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, Processing and Energy Services; Sponsored Investments; and Corporate, as discussed below.

LIQUIDS PIPELINES

Until August 31, 2015, Liquids Pipelines consisted 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, Regional Oil Sands System, Seaway Crude Pipeline System (Seaway Pipeline), Flanagan South Pipeline (Flanagan South), Southern Lights Pipeline, Spearhead Pipeline and Feeder Pipelines and Other. Effective September 1, 2015, under the Canadian Restructuring Plan described below, Enbridge transferred to the Fund Group (comprising Enbridge Income Fund (the Fund), Enbridge Commercial Trust (ECT), Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP), the Canadian Mainline, Regional Oil Sands System, the Canadian portion of the Southern Lights Pipeline and certain residual rights and/or obligations relating to certain terminal and storage assets. The performance of these transferred assets is reported under the Sponsored Investments segment from the date of transfer.

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.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines, gathering and processing facilities and the Company’s energy services businesses, along with renewable energy and transmission facilities. Effective September 1, 2015, under the Canadian Restructuring Plan described below, Enbridge transferred to the Fund Group certain Canadian renewable energy assets which are reported under the Sponsored Investments segment from the date of transfer.

Investments in natural gas pipelines include the Company’s interests in the 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 and Canadian Midstream assets located in northeast British Columbia and northwest Alberta. The energy services businesses undertake physical commodity marketing activity and logistical services, oversee refinery supply services and manage the Company’s volume commitments on Alliance Pipeline, Vector and other pipeline systems.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s overall 89.2% economic interest in the Fund Group. Also included within Sponsored Investments is the Company’s 35.7% economic interest in Enbridge Energy Partners, L.P. (EEP) and Enbridge’s interests in both the Eastern Access and Lakehead System Mainline Expansion projects held through Enbridge Energy, Limited Partnership (EELP). Enbridge, through its subsidiaries, manages the day-to-day operations of and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities.

As a result of the Canadian Restructuring Plan, as discussed below, effective September 1, 2015, the Fund Group’s primary operations include its liquids pipelines business, which includes the Canadian Mainline and Regional Oil Sands System, its renewable power generation assets and a natural gas transmission business through its 50% interest in Alliance Pipeline.

EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines, including the Lakehead Pipeline System (Lakehead System), which is the United States portion of the Enbridge mainline system, and transports, gathers, processes and markets natural gas and NGL.

CORPORATE

Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, general corporate investments and financing costs not allocated to the business segments.

CANADIAN RESTRUCTURING PLAN

On September 1, 2015, Enbridge announced it had completed the transfer of its Canadian Liquids Pipelines business, held through Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines (Athabasca) Inc. (EPAI), and certain Canadian renewable energy assets to EIPLP, in which the Fund has an indirect interest, for aggregate consideration of $30.4 billion plus incentive distribution and performance rights (the Canadian Restructuring Plan or the Transaction).

The Transaction is 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 advances the Company’s sponsored vehicle strategy and supports Enbridge’s 33% dividend increase effective March 1, 2015 and a further 14% dividend increase effective March 1, 2016. The Transaction is expected to provide Enbridge with an alternate source of funding for its enterprise wide growth initiatives and enhance 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, available cash flow from operations (ACFFO), which was introduced in the second quarter of 2015 and is now a part of the Company’s normal course annual and quarterly reporting of financial performance and in the provision of guidance. 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 has established a long-term target payout of 40% to 50% of ACFFO.

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 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, the 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. On November 6, 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.

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 discussed above, Enbridge’s economic interest decreased to 89.2%. 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 to approximately 80% by the end of 2018.

PERFORMANCE OVERVIEW

	Three months ended		Year ended
	December 31,		December 31,
	2015	2014	2015	2014	2013
(millions of Canadian dollars, except per share amounts)
Earnings attributable to common shareholders
Liquids Pipelines1	36	19	(224)	463	427
Gas Distribution	46	69	222	213	129
Gas Pipelines, Processing and Energy Services1	44	185	218	571	(68)
Sponsored Investments1	297	140	479	419	268
Corporate	(45)	(325)	(732)	(558)	(314)
Earnings/(loss) attributable to common shareholders from continuing operations	378	88	(37)	1,108	442
Discontinued operations - Gas Pipelines, Processing and Energy Services	-	-	-	46	4
	378	88	(37)	1,154	446
Earnings/(loss) per common share	0.44	0.11	(0.04)	1.39	0.55
Diluted earnings/(loss) per common share	0.44	0.10	(0.04)	1.37	0.55
Adjusted earnings2
Liquids Pipelines3	64	199	691	858	770
Gas Distribution	58	68	210	177	176
Gas Pipelines, Processing and Energy Services3	(5)	30	89	136	203
Sponsored Investments3	369	123	859	429	313
Corporate	8	(11)	17	(26)	(28)
	494	409	1,866	1,574	1,434
Adjusted earnings per common share2	0.58	0.49	2.20	1.90	1.78
Cash flow data
Cash provided by operating activities	806	656	4,571	2,547	3,341
Cash used in investing activities	(2,296)	(3,737)	(7,933)	(11,891)	(9,431)
Cash provided by financing activities	1,457	3,221	2,973	9,770	5,070
Available cash flow from operations4
Available cash flow from operations	876	610	3,154	2,506	2,527
Dividends
Common share dividends declared	401	297	1,596	1,177	1,035
Dividends paid per common share	0.465	0.350	1.86	1.40	1.26
Revenues1
Commodity sales	6,074	6,192	23,842	28,281	26,039
Gas distribution sales	672	835	3,096	2,853	2,265
Transportation and other services	2,168	1,770	6,856	6,507	4,614
	8,914	8,797	33,794	37,641	32,918
Total assets	84,664	72,857	84,664	72,857	57,568
Total long-term liabilities	51,511	42,306	51,511	42,306	28,277

1 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group within the Sponsored Investments segment (described above under Canadian Restructuring Plan). Losses from the Canadian Liquids Pipelines assets prior to the date of transfer of $403 million in the year ended December 31, 2015 (2014 - earnings of $320 million; 2013 - earnings of $261 million) and earnings from the Canadian renewable energy assets within the Gas Pipelines, Processing and Energy Services segment prior to the date of transfer of $1 million in the year ended December 31, 2015 (2014 - loss of $2 million; 2013 - loss of $55 million), have not been reclassified into the Sponsored Investments segment for presentation purposes. Additionally, a loss of $29 million and earnings of $6 million for the three months ended December 31, 2014, related to Liquids Pipelines assets and Gas Pipelines, Processing and Energy Services assets, respectively, have not been reclassified into the Sponsored Investments segment for presentation purposes.

2 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 12.

3 Adjusted earnings from the Canadian Liquids Pipelines assets prior to the date of transfer of $508 million in the year ended December 31, 2015 (2014 - $688 million; 2013 - $631 million) and adjusted earnings from the Canadian renewable energy assets within the Gas Pipelines, Processing and Energy Services segment prior to the date of transfer under the Canadian Restructuring Plan of $6 million in the year ended December 31, 2015 (2014 - loss of $3 million; 2013 - loss of $4 million), have not been reclassified into the Sponsored Investments segment for presentation purposes. Additionally, adjusted earnings of $146 million and $1 million, for the three months ended December 31, 2014, related to Liquids Pipelines assets and Gas Pipelines, Processing and Energy Services assets, respectively, have not been reclassified into the Sponsored Investments segment for presentation purposes.

4 ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in regulatory assets and liabilities and 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.

EARNINGS/(LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS

Loss attributable to common shareholders was $37 million ($0.04 loss per common share) for the year ended December 31, 2015 compared with earnings of $1,154 million ($1.39 earnings per common share) for the year ended December 31, 2014 and earnings of $446 million ($0.55 earnings per common share) for the year ended December 31, 2013. As discussed below in Performance Overview – Adjusted Earnings, the Company has continued to deliver strong earnings growth from operations over the course of the last three years. However, the positive impact of this growth and the comparability of the Company’s earnings are impacted by a number of unusual, non-recurring or non-operating factors that are listed in Non-GAAP Reconciliations and discussed in the results for each reporting segment, the most significant of which are changes in unrealized derivative fair value gains and losses. 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.

The comparability of the Company’s year-over-year operating results was also impacted by the transfer of assets between entities under common control of Enbridge in connection with the Canadian Restructuring Plan which resulted in $351 million of one-time charges, mainly related to the de-designation of interest rate hedges and a write-off of a regulatory asset in respect of taxes. In addition, the 2015 loss attributable to common shareholders reflects 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 has 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, Midcoast Energy Partners, L.P. (MEP).

Loss for 2015 and earnings for 2014 were also negatively impacted by taxes recognized on the transfer of assets between entities under common control of Enbridge. Intercompany gains realized as a result of these transfers for both years have been eliminated for accounting purposes. However, as these transactions involved the sale of partnership units, all tax consequences have remained in consolidated earnings and resulted in charges of $39 million and $157 million in 2015 and 2014, respectively.

Fourth quarter performance drivers were largely consistent with year-to-date trends and earnings continued to be impacted by changes in unrealized fair value derivative and foreign exchange gains and losses. Aside from the operating factors discussed in Performance Overview – Adjusted Earnings, factors unique to the fourth quarter of 2015 included the impact of employee severance costs in relation to the Company’s enterprise-wide reduction of workforce, which resulted in a net charge of $25 million to earnings across business segments.

ADJUSTED EARNINGS

The Company’s investor value proposition is built upon visible growth, a reliable business model and a growing income and cash flow stream, supported by a rigorous focus on safe and reliable operations and a disciplined approach to investment and project execution. The Company has consistently delivered on this proposition, growing adjusted earnings from $1.78 per common share in 2013 to $1.90 per common share in 2014 and $2.20 per common share in 2015. This growth is a reflection of the underlying strength of Enbridge’s existing asset portfolio combined with the continuing execution of its large growth capital program, which resulted in a number of new assets placed into service over this period. The Company’s current five year plan includes approximately $26 billion of commercially secured growth projects of which approximately $8 billion were brought into service in 2015. The remaining $18 billion are expected to be completed and placed into service between 2016 and 2019.

Following the close of the Canadian Restructuring Plan on September 1, 2015, adjusted earnings from the Canadian Mainline and Regional Oil Sands System are no longer reported in the Liquids Pipeline segment, but are captured in the results of the Fund Group which are reported within Sponsored Investments. Growth in consolidated adjusted earnings was largely driven by stronger contributions from the Canadian Mainline, 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 International Joint Tariff (IJT) Residual Benchmark Toll. In 2015, the Company also benefitted from the full-year of earnings from the Flanagan South and Seaway Twin pipelines, both of which commenced in late 2014. Adjusted earnings from Regional Oil Sands System, however, decreased in 2015 due to a reduction in contracted volumes on the Athabasca Mainline.

The past two years also reflected positive contributions from EEP mainly due to higher throughput and tolls on EEP’s liquids businesses, 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.

EGD, which operates under a five-year customized Incentive Rate Plan (IR Plan) approved in 2014, generated higher adjusted earnings in 2015 primarily attributable to an increase in distribution charges that resulted from an increased asset base, as well as customer growth during the year in excess of expectations embedded in rates.

Within Gas Pipelines, Processing and Energy Services, lower fractionation margins and the loss of a producer processing contract at the Palermo Conditioning Plant have contributed to lower Aux Sable earnings over the past two years. Partially offsetting the decrease in 2015 were higher take-or-pay fees on Canadian Midstream assets and higher contributions from Energy Services. Energy Services benefitted from more favourable tank management opportunities in the first half of 2015 resulting from strong refinery demand for blended crude oil feedstock, partially offset by the effects of less favourable conditions which persisted over the past two years in certain markets accessed by committed transportation capacity involving unrecovered demand charges.

Within the Corporate segment, Other Corporate adjusted loss for the year ended December 31, 2015 decreased compared with 2014, reflecting lower net Corporate segment finance costs in the first half of 2015 and lower income taxes, partially offset by higher preference share dividends reflecting additional preference shares issued in 2014 to fund the Company’s growth capital program.

With respect to the fourth quarter of 2015, many of the annual trends discussed above were also the factors in driving adjusted earnings growth over the fourth quarter of 2014. Within Gas Distribution, although EGD adjusted earnings increased on a year-over-year basis, the timing of higher income taxes and operating and administrative expenses recorded in the fourth quarter of 2015 drove a decrease in quarter-over-quarter adjusted earnings. In Energy Services, the absence of tank management opportunities in the fourth quarter combined with conditions in certain markets as noted above resulted in an adjusted loss in the fourth quarter of 2015 compared with adjusted earnings in the comparable 2014 period.

AVAILABLE CASH FLOW FROM OPERATIONS

ACFFO was $876 million for the three months ended December 31, 2015 compared with $610 million for the three months ended December 31, 2014. 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 Company experienced strong quarter-over-quarter and year-over-year growth in ACFFO which was driven by the same factors as those impacting adjusted earnings across the Company’s various businesses, as discussed in Adjusted Earnings above.

Also contributing to the period-over-period increase in ACFFO were lower maintenance capital expenditures in 2015 compared with the corresponding 2014 periods. 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. The period-over-period decrease in maintenance capital expenditures is due to the completion of specific maintenance programs in 2014. The Company plans to continue to invest in its maintenance capital program to support the safety and reliability of its operations.

The period-over-period increase in ACFFO was partially offset by distributions to noncontrolling interests in EEP and Enbridge Energy Management, L.L.C. (EEM) and to redeemable noncontrolling interests in the Fund. Distributions were higher in 2015 compared with the distributions in 2014 mainly as a result of higher noncontrolling interests and redeemable noncontrolling interests. Also, the Company’s payment of preference share dividends increased period-over-period due to preference shares issued in 2014 to fund the Company’s growth capital program. Finally, the ACFFO for each period was also adjusted for the cash effect of certain unusual, non-recurring or non-operating factors as discussed in Non-GAAP Reconciliations.

ACFFO was $2,506 million for the year ended December 31, 2014 compared with $2,527 million for the year ended December 31, 2013. As discussed in Adjusted Earnings above, the Company experienced a year-over-year growth in its adjusted earnings which also positively impacted its ACFFO. However, this positive effect from adjusted earnings growth was more than offset by higher distributions in 2014 to noncontrolling interests and redeemable noncontrolling interests, higher preference share dividends resulting from preference shares issued over the last two years and higher maintenance capital expenditures in 2014.

IMPACT OF THE RECENT DECLINE IN 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 EEP’s natural gas gathering and processing businesses; 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.

In the third quarter of 2014, the price of crude oil began a dramatic decline. Benchmark prices for crude, which had been trading over US$105 per barrel in June 2014, fell to as low as US$37 per barrel by the end of 2015 as a result of significant increases in production both inside and outside of North America. Prices have declined further since the beginning of 2016, falling to below US$30 per barrel in January and are expected to remain volatile in the near to mid-term as the market seeks to re-balance supply and demand. The current commodity price environment has had an impact on shippers on Enbridge’s pipelines who have responded to price declines by reducing investment in exploration and development programs throughout 2015 and into 2016. 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, the reduction in investment 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 Canadian mainline. Entering 2016, nominations for service on the pipelines have continued to exceed available capacity on the system, resulting in apportionment of nominated volumes. 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.

The decline in oil prices is 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, Enbridge’s most recent near-term supply forecast reaffirms that the expansions and extensions of its liquids pipeline system completed in 2015 and currently in progress will provide cost-effective transportation services to key markets in North America and will be well utilized.

Similar to the crude oil price trend, prices for NGL have decreased sharply as they are, to varying extents, correlated to crude oil. As well, in some cases NGL components have also been experiencing regional supply imbalances that have exacerbated an already challenging environment. Natural gas prices had already been relatively low for some time as production growth continued to outpace demand growth, but the pace of the price decline hastened in 2015 with continuing production levels resulting in rising inventories in storage which reached an all-time record high in November 2015.

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 recently completed expansion of the Company’s liquids mainline system which resulted in the partial alleviation of upstream apportionment experienced in the first half of 2015 and completion of the Company’s reversal and capacity expansion of Line 9B as well as the completion of the Southern Access Extension Project (Southern Access Extension) in the fourth quarter of 2015, which have provided access to the Eastern Canada and Patoka markets, respectively.

CASH FLOWS

Cash provided by operating activities was $4,571 million for the year ended December 31, 2015, mainly driven by strong operating performance from the Company’s core assets, particularly from Liquids Pipelines and Sponsored Investments, and the cash flow generated from growth projects placed into service in recent years. Partially offsetting these cash inflows were changes in operating assets and liabilities as further discussed in Liquidity and Capital Resources.

In 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. However, following the closing of the Canadian Restructuring Plan, Enbridge again began to access the public debt and equity markets in normal course. In 2015, Enbridge through its sponsored vehicles issued equity of approximately $1.1 billion. In addition, Enbridge and its subsidiaries issued approximately $1.6 billion in medium-term notes, US$1.6 billion in senior notes and expanded and extended the average maturity of its secured credit facilities. The proceeds of the capital market transactions, together with additional borrowings from its credit facilities, cash generated from operations and cash on hand were more than sufficient to finance the Company’s approximately $8 billion of projects that were placed into service in 2015 and are expected to provide financing flexibility for the Company’s growth capital program in 2016. As discussed in Liquidity and Capital Resources, the Company also continues to utilize its sponsored vehicles to enhance its enterprise-wide funding program.

DIVIDENDS

The Company has paid common share dividends in every year since it became a publicly traded company in 1953. In December 2015, the Company announced a 14% increase in its quarterly dividend to $0.530 per common share, or $2.120 annualized, effective March 1, 2016.

As described under the Canadian Restructuring Plan, Enbridge’s target dividend payout policy range is 40% to 50% of ACFFO. In 2015, the dividend payout was 50.0% (2014 - 46.4%; 2013 - 40.1%) of ACFFO. For the 10-year period ended December 2015, the Company’s compound annual average dividend growth rate was 13.9%.

REVENUES

The Company generates revenues from three primary sources: commodity sales, gas distribution sales and transportation and other services. Commodity sales of $23,842 million for the year ended December 31, 2015 (2014 - $28,281 million; 2013 - $26,039 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 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 tolls. 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.

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 earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected ACFFO; expected future cash flows; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the Canadian Restructuring Plan (or the Transaction); dividend payout policy and dividend payout expectation.

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; expected exchange rates; inflation; interest rates; availability and price of labour and pipeline 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 impact of the Transaction and dividend policy on the Company’s future cash flows; credit ratings; capital project funding; 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 expected earnings/(loss), adjusted earnings/(loss) and associated per share amounts, ACFFO, the impact of the Transaction on Enbridge or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and pipeline 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 and regulatory approvals on construction and in-service schedules.

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

NON-GAAP RECONCILIATIONS

Earnings/(Loss) to Adjusted Earnings

	Three months ended				Year ended
	December 31,				December 31,
	2015		2014		2015		2014		2013
(millions of Canadian dollars)
Earnings/(loss) attributable to common shareholders	378		88		(37	)	1,154		446
Adjusting items1:
Changes in unrealized derivative fair value loss2	45		164		1,380		320		843
Canadian Restructuring Plan	-		-		351		-		-
Goodwill impairment loss	-		-		167		-		-
Make-up rights adjustments	30		11		30		17		50
Leak remediation costs, net of leak insurance recoveries	(13	)	(9	)	(17	)	8		94
Warmer/(colder) than normal weather	16		(1	)	(11	)	(36	)	(9	)
Gains on sale of non-core assets and investment, net of losses	-		(14	)	(46	)	(71	)	(2	)
Asset impairment losses	13		2		13		2		6
Employee severance costs	25		1		25		1		-
Valuation allowance on deferred income tax assets	-		-		32		-		-
Project development and transaction costs	-		8		14		14		-
Tax on intercompany gains on sale of partnership units	-		157		39		157		-
Out-of-period adjustments	-		-		(71	)	-		25
Other	-		2		(3	)	8		(19	)
Adjusted earnings	494		409		1,866		1,574		1,434

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.

Available Cash Flow from Operations

	Three months ended				Year ended
	December 31,				December 31,
	2015		2014		2015		2014		2013
(millions of Canadian dollars)
Cash provided by operating activities - continuing operations	806		656		4,571		2,528		3,333
Adjusted for changes in operating assets and liabilities1	474		470		688		1,777		272
	1,280		1,126		5,259		4,305		3,605
Distributions to noncontrolling interests	(179	)	(140	)	(680	)	(535	)	(468	)
Distributions to redeemable noncontrolling interests	(34	)	(24	)	(114	)	(79	)	(72	)
Preference share dividends	(74	)	(71	)	(288	)	(245	)	(178	)
Maintenance capital expenditures2	(200	)	(312	)	(720	)	(970	)	(752	)
Significant adjusting items:
Weather normalization	16		(1	)	(11	)	(36	)	(9	)
Project development and transaction costs	2		15		44		19		-
Realized inventory revaluation allowance3	(52	)	-		(474	)	-		-
Hydrostatic testing	23		-		72		-		-
Leak remediation costs, net of leak insurance recoveries	-		-		-		-		345
Employee severance costs	30		6		30		6		-
Other items	64		11		36		41		56
Available cash flow from operations (ACFFO)	876		610		3,154		2,506		2,527

1		Changes in operating assets and liabilities include changes in regulatory assets and liabilities and 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 a dependable and growing income stream.

STRATEGY

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

COMMITMENT TO SAFETY AND OPERATIONAL RELIABILITY

EXECUTE		SECURE THE LONGER-TERM FUTURE
· Focus on project management · Preserve financing strength and flexibility		· Strengthen core businesses · Develop new platforms for growth and diversification

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, bolstering 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 an approximate $26 billion 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 (Major Projects), 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.

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. 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 supports one of the key tenets of the Company’s investor value proposition, a reliable business model.

Enbridge has also actively used its sponsored vehicles, primarily through asset drop downs, to cost-effectively fund a portion of its large growth capital program. In 2015, the Company completed the Canadian Restructuring Plan, which transferred the majority of its Canadian Liquids Pipelines business and certain renewable energy assets to the Fund Group. See Canadian Restructuring Plan. For further discussion on the Company’s financing strategies, refer to Liquidity and Capital Resources.

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

Strengthen Core Businesses

Within the Company’s 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. Over the past year, Enbridge continued to execute on its Gulf Coast Access Program through the completion of a phase of the Mainline Expansion project that increased the capacity of the liquids mainline system by 230,000 barrels per day (bpd) and contributed to record throughput levels on the liquids mainline in December 2015. Significant milestones were also reached on the Company’s Eastern Access Program, as the Company completed the reversal of Line 9B and placed the 300,000 bpd line into service in December 2015. The Eastern Access Program provides increased access to refineries in the upper midwest United States and eastern Canada. Under the Company’s Light Oil Market Access Program, Enbridge completed the Line 9 capacity expansion portion of the Line 9B project noted above as well as Southern Access Extension, which was completed in December 2015 and provides additional crude oil capacity of 300,000 bpd from Flanagan, Illinois to Patoka, Illinois. Additionally, EEP further expanded the capacity of the Lakehead System between Superior, Wisconsin and Griffith, Indiana through the completion of a phase of the Southern Access expansion in May 2015 and the completion of the twinning of the Spearhead North pipeline (Spearhead North Twin) in November 2015.

While executing its record growth capital program in the recent years, the Company has also been undertaking an extensive integrity program across its liquids and gas systems. The Company’s Line 3 Replacement Program (L3R Program) 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. For further details on the L3R Program, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments.

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 $5 billion of regional infrastructure growth projects currently under development which are expected to enter service from 2015 to 2017. Approximately $1 billion worth of projects were completed in 2015. Approximately $4 billion are expected to be completed and placed into service in 2016 and 2017. In the Bakken region, Enbridge and EEP’s growth is focused on the development and construction of the US$2.6 billion Sandpiper Project (Sandpiper). Upon completion, now expected for early 2019, Sandpiper will provide North Dakota producers enhanced access to premium light crude oil markets. For recent developments on this matter, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Sandpiper Project.

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 natural gas and power businesses. The Company’s natural gas strategies include leveraging the competitive advantages of its existing assets, expanding its footprint into emerging supply areas and establishing more direct linkage to growing markets. Combined, Alliance Pipeline and the Aux Sable NGL extraction and fractionation plant are well-positioned to provide liquids-rich gas transportation and processing to developing regions in northeast British Columbia, western Alberta and the Bakken. Alliance Pipeline has successfully re-contracted its firm capacity with shippers for an average contract length of approximately five years under its new services framework that commenced in December 2015. For further details, refer to Sponsored Investments – The Fund Group – Alliance Pipeline Recontracting.

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 during the depressed energy price environment in late 2015 and early 2016, the Montney play continues to attract active rigs. In January 2016, the Company reached agreement to purchase two operating natural gas plants (Tupper Main and Tupper West gas plants) and associated pipelines in northeastern British Columbia. Subject to regulatory review and approval, the transaction is expected to close in the second quarter of 2016. The Company also continues to pursue ultra-deep water offshore natural gas and crude oil transmission opportunities. In 2015, the Big Foot Gas Pipeline portion of the Walker Ridge Gas Gathering System (WRGGS), and the Big Foot Oil Pipeline (Big Foot Pipeline) projects were installed on the sea floor and are awaiting installation of the upstream facilities by producers. Further growth in earnings and cash flow from the Offshore business will come from the Heidelberg Oil Pipeline (Heidelberg Pipeline) which was placed into service in January 2016 and the Stampede Oil Pipeline (Stampede Pipeline) which is expected to be operational by 2018.

Enbridge’s natural gas distribution business in eastern Canada is the largest in Canada with over two million customers. EGD is currently focused on the execution of the Greater Toronto Area (GTA) project, which 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.

In 2014, the Ontario Energy Board (OEB) approved the second generation customized IR Plan which established natural gas distribution rates over a five-year period from 2014 to 2018. A key tenet of the customized IR Plan is that it allows EGD to recover costs for significant capital investment, including the GTA project. The customized IR Plan also allows EGD an opportunity to earn above an allowed return on equity (ROE), with any return over the allowed ROE for a given year to be shared equally with customers. The customized IR Plan serves to reinforce stability of the earnings and cash flow EGD delivers to Enbridge.

Develop New Platforms for Growth and Diversification

The development of new platforms to diversify and sustain long-term growth is an important strategic priority. The Company is currently focusing its development and diversification efforts towards securing investment in additional renewable energy generation, liquefied natural gas (LNG) development, gas-fired power generation and energy marketing, as well as exploring opportunities to extend its energy delivery and generation services to select energy markets outside North America. The Company also invests in early stage energy technologies that complement the Company’s core businesses.

In 2015, Enbridge continued to expand its interests in renewable power generation with the acquisitions of the 103-MW New Creek Wind Project (New Creek) in West Virginia and a 24.9% interest in the 400-MW Rampion Offshore Wind Project (Rampion Project) in the United Kingdom. Including these acquisitions, Enbridge has invested approximately $5 billion in renewable power generation and transmission since 2002.

The Company’s goal is to take over full operational responsibility of its renewable power generation facilities as operating contracts with key service providers expire and if the associated economics are viable. 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 achieve higher earnings from location, grade and time differentials.

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 earn public acceptance of Enbridge and its projects, 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. The Company also focuses on enhancing 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 builds 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 a number of specific projects, programs and initiatives to ensure the perspective of its stakeholders help guide business decision making on sustainable development issues. For example, through its Neutral Footprint Program, originally adopted in 2009, the Company committed to help reduce the environmental impact of its liquid pipeline expansion projects within five years of their occurrence by meeting goals for replacing trees, conserving land and generating kilowatt hours of green energy. During the last five years the Neutral Footprint Program has met these targets and continued to do so in 2015.

The Company has consulted with stakeholders on the development of a next generation of environmental commitments that reflect the shifting energy landscape in North America, including changing business needs, regulatory conditions and public expectations. In 2016 the Company plans to update its environmental goals to address growing public interest in its role on climate and energy issues, as well as new activities and relationships on water protection.

The Company’s CSR Report can be found at http://csr.enbridge.com and progress updates on the Company’s Neutral Footprint initiatives can be found in the annual CSR Report. 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.

To complement community investments in its Canadian and United States operating areas, Enbridge created the energy4everyone Foundation (the Foundation) in 2009. The Foundation aims to leverage the expertise and resources of the Canadian energy industry to effect significant positive change through the delivery and deployment of affordable, reliable and sustainable energy services and technologies in communities in need around the world. To date, the Foundation has completed projects in Costa Rica, Ghana, Nicaragua, Peru and Tanzania.

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. Recently, in view of the commodity price downturn in the energy industry, the Company reduced its workforce by approximately 5% in order to maintain its competitiveness in the industry so it can continue to serve its stakeholders well and further strengthen its foundation for the future. 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 incentives.

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 the Recent Decline in Commodity Prices, crude oil prices fell by close to 50% in the latter half of 2014 and continued to fall to US$37 by the end of 2015, with a further decline to below US$30 in January 2016. 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. The downturn in price has impacted Enbridge’s liquids pipelines’ customers, who have responded by reducing their exploration and development spending for 2015 and into 2016.

Notwithstanding the recent price decline, the Enbridge system has thus far continued to be highly utilized. The mainline system continues to be subject to apportionment of heavy crudes, as nominated volumes currently exceed capacity on portions of the system. Impact of the decline in crude oil prices to 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 Enbridge mainline 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 at a competitive cost relative to other alternatives. The fundamentals of oil sands production and the recent decline in crude oil prices has 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 China and India. While OECD countries, including Canada, the United States and western European nations, will experience population growth, 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.

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 and OPEC. Growth in North America is largely driven by production from the oil sands, the Gulf of Mexico and the continued development of tight oil plays including the Bakken, Eagle Ford and Permian 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 2015 and early 2016, North American supply growth can be influenced by macro-economic factors that drive down the global crude prices. 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.

The combination of relatively flat domestic demand, growing supply and long-lead time to build pipeline infrastructure has led to a fundamental change in the North American crude oil landscape. In recent years, an inability to move increasing inland supply to tide-water markets resulted in a divergence between West Texas Intermediate (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 recently completed by the industry, including those introduced by Enbridge, the crude oil price differentials significantly narrowed in 2015, and resulted in higher netbacks for producers. This has resulted in crude oil moving off of alternative transportation such as rail to fill the additional pipeline capacity as it became available. However, Canadian pipeline export capacity remains essentially full, and production growth once again is increasing its use of non-pipeline transportation services. 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 2015, Enbridge continued to execute its growth projects plan in furtherance of this objective.

As prices continue to remain sensitive to capacity limitations to markets, there is a heightened need to expand access to coastal markets. Details of the Company’s Northern Gateway Project (Northern Gateway), a proposed pipeline system from Alberta to the coast of British Columbia, and associated marine terminal, along with the Company’s other projects under development, can be found in Other Announced Projects Under Development.

SUPPLY AND DEMAND FOR NATURAL GAS AND NGL

Despite the recent slowing of China’s economic growth, global energy demand is expected to increase over time, driven by expected economic growth from non-OECD countries. Natural gas will play an important role in meeting this energy demand and is anticipated to be one of the world’s fastest growing energy sources. Most natural gas demand will stem from the need for greater power generation capacity, as natural gas is a cleaner alternative to coal, which has the largest market share for power generation. Within North America, United States natural gas demand is also expected to be driven by the next wave of gas-intensive petrochemical facilities which are expected to enter service over the next two years along with the commissioning of the first of several LNG export facilities in 2016. Over the longer term, higher United States natural gas demand is expected to be driven by the industrial sector and from power generation and will be supplemented by higher exports, via LNG and 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.

Similar to crude oil, robust North American supply from tight formations has created 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, as well as the rapidly growing Utica shale. The abundance of supply from these shale plays has fundamentally altered natural gas flow patterns in North America. For example, flows from the United States Gulf Coast and WCSB that historically supplied eastern markets, have largely been displaced. Similar pressures are also being felt in the Midwest and southern markets. As a result, 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. While low natural gas prices are expected to be a key driver in future natural gas demand and infrastructure growth, it is also expected that gas supply will remain ample and could respond quickly to rising demand thereby limiting price advances.

With the weak natural gas price environment over the last several years, producers had broadly shifted from dry gas drilling to developing rich gas reservoirs to take advantage of the relatively higher value of NGL inherent in the gas stream. 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. However, the combined effects of much lower crude prices and regional supply imbalances for some NGL products have weakened the economics of NGL extraction to the extent that some producers have returned to drilling prolific dry gas plays which exhibit lower supply costs. Nonetheless, 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. However, until this new infrastructure is completed and online, ethane prices and resulting extraction margins are expected to continue to remain low due to the current oversupply, with high volumes of ethane being retained in the gas stream rather than extracted. 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. In Canada, the WCSB basin is well-situated to capitalize on the evolving NGL fundamentals over the longer term as the Montney formation in northern British Columbia and the Duvernay shale in Alberta contain significant liquids-rich resources at competitive extraction costs. While longer-term NGL fundamentals provide a positive outlook for growth, a sustained period of low crude oil prices and the related negative impact on NGL prices could temper future growth.

Weak prices for NGL, which generally trade at a percentage of crude oil prices, have also caused a reduction in investment for liquids-rich gas drilling programs and related extraction facilities, thereby limiting production growth. However, robust gas production from highly economic core areas within certain shale plays, particularly the Marcellus, is expected to continue to offset any price related production declines from other supply regions over the next year. To the extent oil prices recover, the crude-to-gas price ratio is expected to rise from current levels. The immense and readily available gas supply within North America will likely continue to limit price increases. 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.

Although United States based LNG export projects have successfully executed sales contracts with pricing indexed to North American gas prices, the price for LNG in global markets has typically been more closely linked to crude oil prices, providing western Canadian producers with an opportunity to capture more favourable netbacks on LNG exports upon a recovery in crude prices, if that pricing linkage is maintained. Based on the prospect for higher global LNG demand, the large resource base in western Canada and the changing North American natural gas flow patterns discussed above, there is an expectation that projects to export LNG from the west Coast of Canada will proceed in the next decade. However, a sustained period of low crude oil prices or other changes in global supply and demand for natural gas could delay such opportunities.

In response to these evolving natural gas and NGL fundamentals, Enbridge believes it is well-positioned to provide value-added solutions to producers. Alliance Pipeline traverses through the heart of key liquids-rich plays in the WCSB 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 on the Alliance Pipeline 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. Enbridge is also responding to the need for regional infrastructure with additional investment in Canadian and United States midstream processing and pipeline facilities.

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 both Canada and the United States 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 74 gigawatts (GW) of installed wind power capacity and in Canada over 11 GW of 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 24 GW of installed solar photovoltaic capacity. In addition, 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 (PPA) 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. Over EUR250 billion of investment is forecast in the European offshore wind industry up to 2030. There is also wide public support for carbon reduction targets and broader adoption of renewable generation across all governmental levels. Furthermore, governments in Europe look 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.

Enbridge continues to expand its renewable asset footprint and is one of Canada’s largest wind and solar power generators. In late 2015, Enbridge announced acquisitions of the 103-MW New Creek in West Virginia and a 24.9% interest in the 400-MW Rampion Project in the United Kingdom. Including these acquisitions, Enbridge has invested approximately $5 billion in renewable power generation and transmission since 2002. The Company will continue to seek new opportunities to expand its power generation business, growing its portfolio by investing in assets that meet its investment criteria.

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

A key focus of Enbridge’s corporate strategy is the successful execution of its growth capital program. In 2015, Enbridge successfully placed into service approximately $8 billion of growth projects across several business units. Enbridge’s remaining portfolio of approximately $18 billion of growth projects is expected to be placed into service by 2019, with approximately $2 billion expected to come into service during 2016.

Over the past few years, Enbridge’s growth capital program has been anchored by three major market access initiatives, supported by several mainline system expansion and regional infrastructure projects that are designed to ensure that there is sufficient capacity to support these new market access extensions. The three major market access initiatives are:

· the Gulf Coast Access Program;

· the Eastern Access Program; and

· the Light Oil Market Access Program.

The Gulf Coast Access Program included the Seaway Pipeline, Seaway Crude Pipeline System Twin (Seaway Pipeline Twin) and Flanagan South projects that were completed in 2014, as well as elements of the Canadian Mainline and Lakehead System Mainline expansions. These projects have increased access to refinery markets in the Gulf Coast. In 2015, Enbridge completed its Gulf Coast Access Program with the completion of a phase of the Mainline Expansion project that increased the capacity of the liquids mainline system by 230,000 bpd.

The Company’s Eastern Access Program has allowed for greater access for crude oil into Chicago, further east into Toledo and ultimately into Ontario and Quebec. The Eastern Access Program included the Company’s Toledo pipeline expansion, Line 9 reversal, the Spearhead North pipeline expansion, Line 6B replacement and Line 5 expansion. With the reversal of Line 9B and placement of this 300,000 bpd line into service in December 2015, the Company completed the Eastern Access Program in 2015.

Finally, the Light Oil Market Access Program brings together a group of projects to transport an increasing supply of light oil from Canada and the Bakken and supplement the Eastern Access Program through the upsizing of Line 9B and the Line 6B capacity expansion. The Light Oil Market Access Program also includes Southern Access Extension, Sandpiper, Canadian Mainline System Terminal Flexibility and Connectivity, Spearhead North Twin (Line 78) and Southern Access expansion included within the Lakehead System Mainline Expansion. The Company made significant progress on this program during 2015 completing the capacity expansion portion of the Line 9B project and the Southern Access Extension, both of which were placed into service in December 2015. Additionally, EEP further expanded the capacity of the Lakehead System between Superior, Wisconsin and Griffith, Indiana through the completion of phases of the Southern Access expansion in May 2015 and October 2015, as well as the completion of the Spearhead North Twin (Line 78) in November 2015.

In keeping with the Company’s strategic priority to develop new platforms to diversify and sustain long-term growth, Enbridge continued to expand its renewable energy generation capacity in 2015. The Keechi Wind Project (Keechi) entered service in January 2015, increasing Enbridge’s net operating renewable power generating capacity to nearly 1,800-MW. Enbridge also announced acquisitions of the 103-MW New Creek in West Virginia and a 24.9% interest in the 400-MW Rampion Project in the United Kingdom, which are expected to be placed into service in 2016 and 2018, respectively, increasing Enbridge’s interests to nearly 2,000 MW of net renewable and alternative energy generating capacity.

The following table summarizes the current status of the Company’s commercially secured projects, organized by business segment.

		Estimated Capital Cost1	Expenditures to Date2	Expected In-Service Date	Status
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
1.	Southern Access Extension	US$0.6 billion	US$0.6 billion	2015	Complete


GAS DISTRIBUTION
2.	Greater Toronto Area Project	$0.9 billion	$0.8 billion	2016 (in phases)	Under construction

GAS PIPELINES, PROCESSING AND ENERGY SERVICES
3.	Keechi Wind Project	US$0.2 billion	US$0.2 billion	2015	Complete

4.	Walker Ridge Gas Gathering System	US$0.4 billion	US$0.3 billion	2014-TBD (in phases)	Complete
5.	Big Foot Oil Pipeline	US$0.2 billion	US$0.2 billion	TBD	Complete

6.	Heidelberg Oil Pipeline	US$0.1 billion	US$0.1 billion	2016	Complete

7.	Tupper Main and Tupper West Gas Plants	$0.5 billion	No significant expenditures to date	2016	Acquisition in progress
8.	Aux Sable Extraction Plant Expansion	US$0.1 billion	No significant expenditures to date	2016	Under construction
9.	New Creek Wind Project	US$0.2 billion	No significant expenditures to date	2016	Pre- Construction
10.	Stampede Oil Pipeline	US$0.2 billion	No significant expenditures to date	2018	Pre- construction
11.	Rampion Offshore Wind Project	$0.8 billion (£0.37 billion)	$0.2 billion (£0.10 billion)	2018	Under construction
SPONSORED INVESTMENTS
12.	The Fund Group - Eastern Access Line 9 Reversal and Expansion	$0.8 billion	$0.8 billion	2013-2015 (in phases)	Complete
13.	The Fund Group - Canadian Mainline Expansion	$0.7 billion	$0.7 billion	2015	Complete
14.	The Fund Group - Surmont Phase 2 Expansion	$0.3 billion	$0.3 billion	2014-2015 (in phases)	Complete
15.	The Fund Group - Canadian Mainline System Terminal Flexibility and Connectivity	$0.7 billion	$0.7 billion	2013-2015 (in phases)	Complete
16.	The Fund Group - Woodland Pipeline Extension	$0.7 billion	$0.7 billion	2015	Complete
17.	The Fund Group - Sunday Creek Terminal Expansion	$0.2 billion	$0.2 billion	2015	Complete

		Estimated Capital Cost1	Expenditures to Date2	Expected In-Service Date	Status
18.	The Fund Group - Edmonton to Hardisty Expansion	$1.6 billion	$1.6 billion	2015 (in phases)	Complete
19.	The Fund Group - AOC Hangingstone Lateral	$0.2 billion	$0.2 billion	2015	Complete
20.	The Fund Group - JACOS Hangingstone Project	$0.2 billion	$0.1 billion	2016	Under construction
21.	The Fund Group - Regional Oil Sands Optimization Project	$2.6 billion	$1.6 billion	2017	Under construction
22.	The Fund Group - Norlite Pipeline System3	$1.3 billion	$0.2 billion	2017	Under construction
23.	The Fund Group - Canadian Line 3 Replacement Program	$4.9 billion	$0.9 billion	2019	Pre- construction
24.	EEP - Beckville Cryogenic Processing Facility	US$0.2 billion	US$0.2 billion	2015	Complete
25.	EEP - Eastern Access4	US$2.7 billion	US$2.4 billion	2013-2016 (in phases)	Under construction
26.	EEP - Lakehead System Mainline Expansion4	US$2.4 billion	US$2.0 billion	2014-2019 (in phases)	Under construction
27.	EEP - Eaglebine Gathering	US$0.2 billion	US$0.1 billion	2015-TBD (in phases)	Complete (Phase I)
28.	EEP - Sandpiper Project5	US$2.6 billion	US$0.7 billion	2019	Pre- construction
29.	EEP - U.S. Line 3 Replacement Program	US$2.6 billion	US$0.3 billion	2019	Pre- 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, 2015.

3 The Company will construct and operate the Norlite Pipeline System (Norlite). Keyera Corp. (Keyera) will fund 30% of the project.

4 The Eastern Access and Lakehead System Mainline Expansion projects are funded 75% by Enbridge and 25% by EEP.

5 The Company will construct and operate Sandpiper. Marathon Petroleum Corporation (MPC) will fund 37.5% of the project.

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

LIQUIDS PIPELINES

Southern Access Extension

The Southern Access Extension joint venture involved the construction of a new 265-kilometre (165-mile), 24-inch diameter crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, for an initial capacity of approximately 300,000 bpd, as well as additional tankage and two new pump stations. The project was placed into service in December 2015 and the Company’s share of the total capital cost was approximately US$0.6 billion.

GAS DISTRIBUTION

Greater Toronto Area Project

EGD is undertaking 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 involves 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), both of which are now expected to enter service by the end of the first quarter of 2016, as well as related facilities to upgrade the existing distribution system in Toronto, Ontario, that delivers natural gas to several municipalities in the GTA. The project is now expected to cost approximately $0.9 billion due to greater complexity in the construction and requirements from government and permitting agencies. Expenditures incurred to date are approximately $0.8 billion.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Keechi Wind Project

In 2014, Enbridge announced it had entered into an agreement with Renewable Energy Systems Americas Inc. (RES Americas) to own and operate the 110-MW Keechi, located in Jack County, Texas. The project was constructed by RES Americas under a fixed price, engineering, procurement and construction agreement at a total cost of approximately US$0.2 billion, and it entered service in January 2015. The electricity generated by Keechi is delivered into the Electric Reliability Council of Texas, Inc. market under a 20-year PPA with Microsoft Corporation.

Walker Ridge Gas Gathering System

The Company has agreements with Chevron USA Inc. (Chevron) and Union Oil Company of California, and their co-owners, to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, the Company has constructed and will own and operate 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 million cubic feet per day (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 investigate the extent of the delay. The Company began collecting certain fees in 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 has 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.

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 January 2016, Enbridge announced the acquisition of the Tupper Main and Tupper West gas plants (the Tupper Plants) and associated pipelines from a Canadian subsidiary of Murphy Oil Corporation (Murphy Oil) for a purchase price of approximately $0.5 billion. The Tupper Plants have a combined total licensed capacity of 320 mmcf/d and are located within the Montney gas play, 35 kilometres 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 of high pressure pipelines, are currently in operation and are underpinned by long-term take-or-pay contracts. The purchase price will initially be funded from available sources of liquidity and the acquisition, subject to regulatory review and approval, is anticipated to close by the second quarter of 2016.

Aux Sable Extraction Plant Expansion

In 2014, the Company approved the expansion of fractionation capacity and related facilities at the Aux Sable extraction and fractionation plant located in Channahon, Illinois. The expansion 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 expansion is expected to provide approximately 24,500 bpd of incremental fractionation capacity and is expected to be placed into service in the second quarter of 2016. The Company’s share of the project cost is approximately US$0.1 billion.

New Creek Wind Project

In November 2015, Enbridge announced it had acquired a 100% interest in the 103-MW New Creek, located in Grant County, West Virginia, from EverPower Wind Holdings, LLC. Enbridge’s total investment is expected to be approximately US$0.2 billion. New Creek will comprise 49 Gamesa turbines and is targeted to be in service in December 2016. The project will be constructed under a fixed-price engineering, procurement and construction agreement, with White Construction Inc. Gamesa will provide turbine operations and maintenance services under a five-year fixed price contract. The project is backed by renewable energy credit sales and medium and long-term offtake agreements.

Stampede Oil Pipeline

In January 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.

Rampion Offshore Wind Project

In November 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 (E.ON). 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 retaining the balance of 50.1% interest. Enbridge has incurred costs to date of approximately $0.2 billion (£0.10 billion).

SPONSORED INVESTMENTS

As part of the Canadian Restructuring Plan, the commercially secured growth programs embedded within EPI and EPAI were transferred to the Fund Group and are now presented in Sponsored Investments. Enbridge continues to oversee the execution of the growth program, as well as manage the operations and future development opportunities of these assets. Reference to “the Company” in this Sponsored Investments section includes activities performed by the Fund Group, or on its behalf by Enbridge, following the completion of the Canadian Restructuring Plan.

The Fund Group

Eastern Access

The Eastern Access initiative includes 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. Projects undertaken by the Company include a reversal of Line 9A and expansion of the Toledo Pipeline, both completed in 2013, as well as the reversal of Line 9B and expansion of Line 9 (together, Line 9), which was placed into service in December 2015. For discussion on EEP’s portion of Eastern Access, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access.

The Company completed the reversal of its 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in that province. The Line 9B reversal was initially expected to be completed at an estimated cost of approximately $0.3 billion. Following an open season held on the Line 9B reversal project, further commitments were received that required additional delivery capacity into Ontario and Quebec, resulting in the Line 9 capacity expansion project. The Line 9 capacity expansion increased the annual capacity of Line 9 from 240,000 bpd to 300,000 bpd at an estimated cost of approximately $0.1 billion.

The Line 9B Reversal and Line 9 Capacity Expansion projects were approved by the National Energy Board (NEB) in March 2014 subject to 30 conditions. In October 2014, the NEB requested additional information regarding one of the conditions imposed on the Line 9B Reversal and Line 9 Capacity Expansion Project. On October 23, 2014, the Company responded to the NEB describing the Company’s rigorous approach to risk management and isolation valve placement. On February 6, 2015, the NEB approved Conditions 16 and 18, the two conditions in the NEB’s order requiring approval, and the Company filed for a Leave to Open (LTO), which is a prerequisite to allowing the operation of the project. In its February approval, the NEB also imposed additional obligations on the Company that directed the Company to take a “life-cycle” approach to water crossings and valves, requiring it to perform ongoing analysis to ensure optimal protection of the area’s water resources. On June 18, 2015, the NEB approved the LTO application and issued a separate order imposing further conditions requiring the Company to perform hydrostatic tests of selected segments of the pipeline. The Company filed its hydrostatic test plan with the NEB on July 23, 2015, which was approved on July 27, 2015. Hydrostatic testing was completed and the Company submitted the test results to the NEB in September 2015. On September 30, 2015 the NEB confirmed that the hydrostatic tests successfully met their criteria. Line-fill commenced in late October 2015 and the pipeline was placed into service in December 2015.

Costs related to conditions imposed by the NEB, including valve placement and hydrostatic testing, increased the total project cost at in-service to $0.8 billion, inclusive of costs related to the previously mentioned Line 9A reversal. Pursuant to various agreements with shippers, the Company is able to recover from shippers the full costs of compliance with NEB imposed hydrostatic testing and the valve replacement program.

On July 31, 2014, the Company filed an application for tolls on Line 9. After complaints from shippers on Line 9 were filed with the NEB with respect to the inclusion of mainline surcharges in the Line 9 toll, the NEB approved the tolls on an interim basis to allow for time to engage shippers in further discussions to attempt to resolve the outstanding issues. On January 30, 2015, the NEB convened a hearing to consider the matter. In response to a request from the Company that was supported by the shippers, the hearing was suspended to allow the Company and shippers to engage in further discussions to resolve the outstanding issues. In the third quarter of 2015, the Company and the shippers came to an agreement to recover mainline surcharges in the Line 9 toll.

Canadian Mainline Expansion

The Company undertook an expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba. The scope of the project consisted of two phases that involved the addition of pumping horsepower to raise the capacity of the Alberta Clipper line from 450,000 bpd to 800,000 bpd. The initial phase to increase capacity from 450,000 bpd to 570,000 bpd was completed in the third quarter of 2014 at an estimated capital cost of approximately $0.2 billion. The second phase to increase capacity from 570,000 bpd to 800,000 bpd was completed in July 2015 at an expected cost of approximately $0.5 billion. The total cost of the entire expansion was approximately $0.7 billion. Receipt of the final regulatory approval on EEP’s portion of the mainline system expansion has been delayed. EEP continues to work with regulatory authorities; however, the timing of the federal regulatory approval cannot be determined at this time. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with this delay. See Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Mainline Expansion.

Surmont Phase 2 Expansion

In 2013, the Company entered into a terminal services agreement with ConocoPhillips Canada Resources Corp. (ConocoPhillips) and Total E&P Canada Ltd. (together, the ConocoPhillips Partnership) to expand the Cheecham Terminal to accommodate incremental bitumen production from Surmont’s Phase 2 expansion. The Company constructed two new 450,000 barrel blend tanks and converted an existing tank from blend to diluent service. The expansion occurred in two phases with the blended product system placed into service in November 2014 and the diluent system placed into service in March 2015 at a total cost of approximately $0.3 billion.

Canadian Mainline System Terminal Flexibility and Connectivity

As part of the Light Oil Market Access Program initiative, the Company undertook the Canadian Mainline System Terminal Flexibility and Connectivity project in order to accommodate additional light oil volumes and enhance the operational flexibility of the Canadian mainline terminals. The modifications comprised of upgrading existing booster pumps, installing additional booster pumps and adding new tank line connections. These projects had varying completion dates from 2013 through the second quarter of 2015. The total cost of the project was approximately $0.7 billion.

Woodland Pipeline Extension

The joint venture Woodland Pipeline Extension Project extended the Woodland Pipeline south from the Company’s Cheecham Terminal to its Edmonton Terminal. The extension is a 388-kilometre (241-mile), 36-inch diameter pipeline with an initial capacity of 400,000 bpd, expandable to 800,000 bpd. The project was completed and placed into service in July 2015. The Company’s share of the project costs was approximately $0.7 billion.

Sunday Creek Terminal Expansion

In 2014, the Company announced the construction of additional facilities at its existing Sunday Creek Terminal, located in the Christina Lake area of northern Alberta, to support production growth from the Christina Lake oil sands project operated by Cenovus Energy Inc. and jointly owned with ConocoPhillips. The expansion included development of a new site adjacent to the existing terminal, construction of a new 350,000 barrel tank with associated piping, pumps and measurement equipment, as well as civil construction work for a future tank. The project was placed into service in August 2015 at an approximate cost of $0.2 billion.

Edmonton to Hardisty Expansion

The expansion of the Canadian Mainline system between Edmonton, Alberta and Hardisty, Alberta included 181 kilometres (112 miles) of new 36-inch diameter pipeline and provides an initial capacity of approximately 570,000 bpd, expandable to 800,000 bpd. The new line generally follows the same route as the Company’s existing Line 4 pipeline. Also included in the project scope were connections into existing infrastructure at the Hardisty Terminal and new terminal facilities in Edmonton, Alberta which include five new 500,000 barrel tanks. The new pipeline was placed into service in April 2015, with additional tankage requirements completed in December 2015. The project was placed into service at a cost of approximately $1.6 billion.

AOC Hangingstone Lateral

In 2013, the Company entered into an agreement with Athabasca Oil Corporation (AOC) to provide pipeline and terminalling services to the proposed AOC Hangingstone Oil Sands Project (AOC Hangingstone) in Alberta. Phase I of the project involved the construction of a new 49-kilometre (31-mile), 16-inch diameter pipeline from the AOC Hangingstone project site to the Company’s existing Cheecham Terminal and related facility modifications at Cheecham, Alberta. This phase of the project provides an initial capacity of 16,000 bpd and was placed into service in December 2015 at a cost of approximately $0.2 billion. Phase 2 of the project, which is subject to commercial approval, would provide up to an additional 60,000 bpd for a total capacity of 76,000 bpd.

JACOS Hangingstone Project

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, is expected to enter service by the end of 2016. 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

In March 2015, the Company announced a plan to optimize previously announced expansions of its Regional Oil Sands System currently in execution. The Company previously announced the Wood Buffalo Extension, which includes the construction of a 30-inch pipeline, from the Company’s Cheecham Terminal to its Battle River Terminal at Hardisty, Alberta and associated terminal upgrades, and the Athabasca Pipeline Twin, which consists of 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.

The optimization plan, which has been agreed to with the affected shippers, including Suncor Energy Inc., Total E&P Canada Ltd. and Teck Resources Limited (the Fort Hills Partners), will enable deferral of the southern segment of the Wood Buffalo Extension by connecting it to the Athabasca Pipeline Twin. The optimization 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 now connect to the origin of the Athabasca Pipeline Twin at Kirby Lake, Alberta. The capacity of the Athabasca Pipeline Twin will be expanded from 450,000 bpd to 800,000 bpd through additional horsepower.

The definitive cost estimate of the Wood Buffalo Extension was finalized at approximately $1.8 billion before optimization. As a result of the optimization, the cost estimate to complete the integrated Wood Buffalo Extension and Athabasca Pipeline Twin projects is expected to decrease from approximately $3.0 billion to approximately $2.6 billion. Expenditures on the joint projects to date are approximately $1.6 billion.

The integrated Wood Buffalo Extension and Athabasca Pipeline Twin will transport diluted bitumen from the proposed Fort Hills Partners’ oil sands project (Fort Hills Project) in northeastern Alberta, as well as from oil sands production from Suncor Energy Oil Sands Limited Partnership (Suncor Partnership) in the Athabasca region. The Wood Buffalo Extension and the Athabasca Pipeline Twin will ship blended bitumen from the Fort Hills Project and have an expected 2017 in-service date. The Athabasca Pipeline Twin will also ship blended bitumen from the Cenovus Christina Lake Steam Assisted Gravity Drainage project near the origin of the Athabasca Pipeline Twin.

Norlite Pipeline System

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, which will provide an initial capacity of approximately 224,000 bpd of diluent, with the potential to be further expanded to approximately 400,000 bpd of capacity with the addition of pump stations. Norlite will be anchored by throughput commitments from the Fort Hills Partners for production from the proposed Fort Hills Project and from Suncor Partnership’s 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 2017 at an estimated cost of approximately $1.3 billion, with expenditures to date of approximately $0.2 billion.

Canadian Line 3 Replacement Program

In 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. 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. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the overall system, enhance flexibility and allow the Company to optimize throughput on the mainline system’s overall western Canada export capacity. The L3R Program is expected to achieve capacity of approximately 760,000 bpd.

With the NEB hearing for the Canadian L3R Program application ending in December 2015, the application record is now closed with Final Conditions and a recommendation to the Federal Cabinet (the Cabinet) expected by the end of the first quarter of 2016. A decision by the Cabinet was expected to be issued by July 2016 per guidelines; however, the Company is awaiting confirmation following the Federal Government’s January 27, 2016 announcement that outside of the NEB process for industry projects, it has directed Federal agencies to conduct assessments of direct and upstream greenhouse gas emissions and incremental consultation with affected communities and Indigenous peoples. Depending on the scope of this new process, the expected timeline for final regulatory approval to commence construction could be extended.

The Company has reached a settlement agreement with landowner associations representing Line 3 landowners in Canada and as a result these parties have withdrawn from the hearing process and have expressed their support for the project.

Subject to regulatory and other approvals, the Canadian L3R Program is now targeted to be completed in early 2019 at an estimated capital cost of approximately $4.9 billion, with expenditures to date of approximately $0.9 billion. With a delay in construction, the cost of this project is expected to increase. The Company continues to review the estimated cost of this project. Costs of the Canadian L3R Program will be recovered through a 15-year toll surcharge mechanism under the CTS. For discussion on EEP’s portion of the L3R Program, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – United States Line 3 Replacement Program.

Enbridge Energy Partners, L.P.

Beckville Cryogenic Processing Facility

EEP and its partially-owned subsidiary, MEP, have constructed a cryogenic natural gas processing plant near Beckville (the Beckville Plant) in Panola County, Texas. The Beckville Plant offers incremental processing capacity for existing and future customers in the 10-county Cotton Valley shale region, where the East Texas system is located. The Beckville Plant has a natural gas processing capability of 150 mmcf/d and is expected to produce 8,500 bpd of NGL. The Beckville Plant was placed into service in May 2015 at a cost of approximately US$0.2 billion.

Eastern Access

The Eastern Access initiative includes 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. Projects undertaken by EEP included an expansion of Line 5 and of the United States mainline involving the Spearhead North Pipeline (Line 62), both completed in 2013, and replacement of additional segments of Line 6B, completed in 2014. The cost of these projects was approximately US$2.4 billion. For discussion on the Company’s portion of Eastern Access, refer to Growth Projects – Commercially Secured Projects –Sponsored Investments – The Fund Group – Eastern Access.

Additionally, the Eastern Access initiative also includes a further upsizing of EEP’s Line 6B. The Line 6B capacity expansion from Griffith, Indiana to Stockbridge, Michigan will increase capacity from 500,000 bpd to 570,000 bpd and will include pump station modifications at the Griffith, Niles and Mendon stations, additional modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. The Line 6B capacity expansion is now expected to be placed into service in mid-2016 at an estimated cost of approximately US$0.3 billion.

The total estimated cost of the projects being undertaken by EEP as part of the Eastern Access initiative, including the Line 6B capacity expansion project, is approximately US$2.7 billion, with expenditures to date of approximately US$2.4 billion. The Eastern Access projects undertaken by EEP are being funded 75% by Enbridge and 25% by EEP. Within one year of the final in-service date of the collective projects, EEP will have the option to increase its economic interest held at that time by up to an additional 15%. On July 30, 2015, Enbridge and EEP reached an agreement to forego distributions to 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, Enbridge’s capital funding contribution requirements to the Eastern Access projects will be netted against its foregone cash distribution during this period.

Lakehead System Mainline Expansion

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 to 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 (Line 78).

The current scope of the Alberta Clipper expansion between the border and Superior, Wisconsin consists of two phases. The initial phase increased capacity from 450,000 bpd to 570,000 bpd at an estimated capital cost of approximately US$0.2 billion. The second phase increased capacity from 570,000 bpd to 800,000 bpd at an estimated capital cost of approximately US$0.2 billion. The initial phase was completed in the third quarter of 2014 and the second phase was completed in July 2015. Both phases of the Alberta Clipper expansion required only the addition of pumping horsepower with no pipeline construction and are subject to regulatory approvals, including an amendment to the current Presidential border crossing permit to allow for operation of Line 67 at its currently planned operating capacity of 800,000 bpd. EEP continues to work with regulatory authorities; however, the timing of receipt of the amendment to the Presidential border crossing permit to allow for increased flow on Alberta Clipper across the border cannot be determined at this time. 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.

In November 2014, several environmental and Native American groups filed a complaint in the United States District Court in Minnesota (the Court) against the United States Department of State (DOS). The Complaint alleges, among other things, that the DOS is in violation of the United States’ National Environmental Policy Act by acquiescing in the Company’s use of permitted cross border capacity on other pipelines to achieve the transportation of amounts in excess of Alberta Clipper’s current permitted capacity while the review and approval of the Company’s application to the DOS to increase Alberta Clipper’s permitted cross border capacity is still pending. On December 9, 2015 the Court ruled that the United States’ State Department’s interpretation of Enbridge’s Presidential permits is not reviewable by a federal court on constitutional grounds.

The scope of the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois also consists of phases that require only the addition of pumping horsepower with no pipeline construction. The initial phase to increase the capacity from 400,000 bpd to 560,000 bpd was completed in August 2014 at an estimated capital cost of approximately US$0.2 billion. EEP further expanded the pipeline capacity to 800,000 bpd in May 2015 at an estimated capital cost of approximately US$0.4 billion. Additional tankage is expected to cost approximately US$0.4 billion with various completion dates that began in the third quarter of 2015 and are expected to continue through the third quarter of 2016. In the first quarter of 2015, the Company, in conjunction with shippers, decided to delay the in-service date of a further expansion phase to increase the pipeline capacity to 1,200,000 bpd at an estimated capital cost of approximately US$0.5 billion, to align more closely with the anticipated in-service date for Sandpiper. In October 2015, a portion of this phase was placed into service early to address capacity constraints, increasing the pipeline capacity to 950,000 bpd. The remaining capacity is now expected to be in service in early 2019 in line with the expected in-service date of Sandpiper.

As part of the Light Oil Market Access Program, EEP expanded the capacity of the Lakehead System between Flanagan, Illinois and Griffith, Indiana by constructing a 127-kilometre (79-mile), 36-inch diameter twin of the existing Spearhead North Pipeline (Line 62), with an initial capacity of 570,000 bpd. The completed Spearhead North Twin (Line 78) project was placed into service in November 2015 at a cost of approximately US$0.5 billion.

The projects collectively referred to as the Lakehead System Mainline Expansion are now expected to cost approximately US$2.4 billion, with expenditures incurred to date of approximately US$2.0 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. On July 30, 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, Enbridge’s capital funding contribution requirements to the Lakehead System Mainline Expansion will be netted against its foregone cash distribution during this period.

Eaglebine Gathering

In February 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. EEP and MEP completed construction of the Ghost Chili pipeline project, consisting of a lateral and associated facilities that create 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. 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. MEP also acquired New Gulf Resources, LLC’s midstream business in Leon, Madison and Grimes Counties, Texas. The acquisition consists of a natural gas gathering system that is currently in operation. Expenditures incurred to date are approximately US$0.1 billion.

Sandpiper Project

As part of the Light Oil Market Access Program initiative, EEP plans to undertake Sandpiper, which will expand and extend EEP’s North Dakota feeder system. The Bakken takeaway capacity of the North Dakota System will be expanded by 225,000 bpd to a total of 580,000 bpd. The proposed expansion will involve 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 will twin 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.

EEP is in the process of obtaining the appropriate permits for constructing Sandpiper in Minnesota. The project requires both a Certificate of Need and Route Permit from the Minnesota Public Utilities Commission (MNPUC). On August 3, 2015, the MNPUC issued an order granting a Certificate of Need and a separate order restarting the Route Permit proceedings. On September 14, 2015 the Minnesota Court of Appeals reversed the MNPUC’s Certificate of Need order stating that an Environmental Impact Statement must be prepared prior to reaching a final decision in cases where proceedings have been separated and handled sequentially. On January 11, 2016 the MNPUC issued a written order (the Sandpiper Order) re-joining the Certificate of Need and Route Permit process, requiring the Department of Commerce to commence preparation of an Environmental Impact Statement, ordering the Office of Administrative Hearings to recommence processing the Certificate of Need and Route Permit applications but to take judicial notice of the record already developed for the Certificate of Need, and to require that a final Environmental Impact Statement be issued before the Certificate of Need and Route Permit processes commence. The Company believes that the directions from the MNPUC in most of the decisions set out in the Sandpiper Order were consistent with expectations and provide clarity on process matters; however, Enbridge believes that the requirement to have a final Environmental Impact Statement prior to beginning the Certificate of Need and Route Permit processes is unprecedented and contrary to Minnesota law. On February 1, 2016, EEP filed a Petition for Reconsideration of this aspect of the Sandpiper Order. If upheld, the Sandpiper Order will result in delays in the processing of the applications and an increase in the cost of the project.

Subject to regulatory and other approvals, Sandpiper is now expected to be completed in early 2019 at an estimated capital cost of approximately US$2.6 billion, with expenditures incurred to date of approximately US$0.7 billion. The Company continues to review the impact of the Sandpiper Order on the project’s schedule and cost estimates.

MPC has been secured as an anchor shipper for Sandpiper. As part of the arrangement, EEP, through its subsidiary, North Dakota Pipeline Company LLC (NDPC) (formerly known as Enbridge Pipelines (North Dakota) LLC), and Williston Basin Pipeline LLC (Williston), an affiliate of MPC, entered into an agreement to, among other things, admit Williston as a member of NDPC. Williston will fund 37.5% of Sandpiper construction and will have the option to participate in other growth projects within NDPC, unless specifically excluded by the agreement; this investment is not to exceed US$1.2 billion in aggregate. In return for funding part of Sandpiper’s construction, Williston will obtain an approximate 27% equity interest in NDPC at the in-service date of Sandpiper.

United States Line 3 Replacement Program

In 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. EEP expects to undertake the United States portion of the L3R Program (U.S. L3R Program) which 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. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the overall system, enhance flexibility and allow the Company to optimize throughput on the mainline system’s overall western Canada export capacity. The L3R Program is expected to achieve capacity of approximately 760,000 bpd.

The MNPUC found both the Certificate of Need and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. The MNPUC had sent the Certificate of Need application to the Administrative Law Judge (ALJ) for a pre-hearing meeting to establish a schedule. With respect to the Route Permit, the Minnesota Department of Commerce held public scoping meetings in August 2015. As a result of the Court of Appeals decision in the Sandpiper docket, the ALJ requested direction on how to proceed with the Certificate of Need process for Line 3. 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 Department of Commerce to prepare an Environmental Impact Statement 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. The Company believes that the directions from the MNPUC in most of the decisions set out in the U.S. L3R Order were consistent with expectations and provide clarity on process matters; however, Enbridge believes that the requirement to have a final Environmental Impact Statement prior to beginning the Certificate of need and Route Permit processes is unprecedented and contrary to Minnesota law. On February 5, 2016 EEP filed a Petition for Reconsideration of this aspect of the U.S. L3R Order. If upheld, the U.S. L3R Order will result in further delays in the processing of the applications and an increase in the cost of the project.

Subject to regulatory and other approvals, the U.S. L3R Program is now expected to be completed in early 2019 at an estimated capital cost of approximately US$2.6 billion, with expenditures to date of approximately US$0.3 billion. The Company continues to review the impact of the U.S. L3R Order on the U.S. L3R Program’s schedule and cost estimates. The U.S. L3R Program will be jointly funded by Enbridge and EEP at participation levels that are subject to finalization. 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.

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 attractive projects under development that have not yet progressed to the point of public announcement. In its long-term funding plans, the Company makes full provision for all commercially secured projects and makes provision for projects under development based on an assessment of the aggregate securement success anticipated. Actual securement success achieved could exceed or fall short of the anticipated level.

LIQUIDS PIPELINES

Northern Gateway Project

Northern Gateway involves 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 is 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 is proposed to be a 20-inch diameter line with an initial capacity of 193,000 bpd.

In 2010, Northern Gateway submitted an application to the NEB and the Joint Review Panel (JRP) was established to review the proposed project, pursuant to the NEB Act and the Canadian Environmental Assessment Act. The JRP 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.” The Government of Canada consulted with Aboriginal groups on the JRP report and its recommendations prior to making its decision on whether to direct the NEB to issue the Certificates of Public Convenience and Necessity for the pipelines.

In June 2014, the Governor in Council approved Northern Gateway, subject to 209 conditions following the recommendation from the JRP. The Company continues to work closely with its customers in advancing this project to open West Coast market access and is making progress in fulfilling the conditions and building relationships and trust with communities and Aboriginal groups along the proposed route.

Nine applications to the Federal Court of Appeal (Federal Court) for leave for judicial review of the Order in Council 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 Federal Court consolidated the nine applications into one proceeding. The hearing of these applications commenced in Vancouver, British Columbia, on October 1, 2015 and concluded on October 8, 2015. Depending on the outcome of these proceedings, which is anticipated for 2016, an application for Leave to Appeal to the Supreme Court of Canada is a possibility.

The Company reviewed an updated cost estimate of Northern Gateway based on full engineering analysis of the pipeline route and terminal location. Based on this comprehensive review, the Company expects that the final cost of the project will be substantially higher than the preliminary cost figures included in the Northern Gateway filing with the JRP, which reflected a preliminary estimate prepared in 2004 and escalated to 2010. The drivers behind this substantial increase include the significant costs associated with escalation of labour and construction costs, satisfying the 209 conditions imposed in the Governor in Council approval, a larger portion of high cost pipeline terrain, more extensive terminal site rock excavations and a delayed anticipated in-service date. The updated cost estimate is currently being assessed and refined by Northern Gateway and the potential shippers. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.6 billion, of which approximately half is being funded by potential shippers on Northern Gateway.

The in-service date of the project will be dependent upon the timing and outcome of judicial reviews, continued commercial support, receipt of regulatory and other approvals and adequately addressing landowner and local community concerns (including those of Aboriginal communities). Of the 48 Aboriginal groups eligible to participate as equity owners, 28 have signed up to do so.

Given the many uncertainties surrounding Northern Gateway, including final ownership structure, the potential financial impact of the project cannot be determined at this time.

The JRP posts public filings related to Northern Gateway on its website at http://gatewaypanel.review-examen.gc.ca/clf-nsi/hm-eng.html and Northern Gateway also maintains a website at www.northerngateway.ca where the full regulatory application submitted to the NEB, the 2010 Enbridge Northern Gateway Community Social Responsibility Report and the December 19, 2013 Report of the JRP on the Northern Gateway Application are available. Unless otherwise specifically stated, none of the information contained on, or connected to, the JRP website or the Northern Gateway website is incorporated by reference in, or otherwise part, of this MD&A.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

NEXUS Gas Transmission Project

In 2012, Enbridge, DTE Energy Company (DTE) and Spectra Energy Corp. (Spectra) announced the execution of a Memorandum of Understanding (MOU) to jointly develop the NEXUS Gas Transmission System, a project that would move growing supplies of Ohio Utica shale gas to markets in the United States midwest, including Ohio and Michigan, and Ontario, Canada. The MOU has expired and Enbridge is in discussions with Spectra and DTE regarding terms for its potential participation in the project.

LIQUIDS PIPELINES

EARNINGS

	2015		2014		2013
(millions of Canadian dollars)
Canadian Mainline	395		500		460
Regional Oil Sands System	108		181		170
Seaway and Flanagan South Pipelines	103		74		48
Spearhead Pipeline	34		31		31
Southern Lights Pipeline	11		49		49
Feeder Pipelines and Other	40		23		12
Adjusted earnings	691		858		770
Canadian Mainline - changes in unrealized derivative fair value
loss	(819	)	(370	)	(268	)
Canadian Mainline - Line 9B costs incurred during reversal	(5	)	(8	)	-
Canadian Mainline - write-off of regulatory asset in respect of taxes	(88	)	-		-
Canadian Mainline - impact of tax rate changes	9		-		-
Regional Oil Sands System - make-up rights adjustment	9		6		(13	)
Regional Oil Sands System - leak insurance recoveries	9		8		-
Regional Oil Sands System - leak remediation and long-term pipeline
stabilization costs	(5	)	(4	)	(56	)
Regional Oil Sands System - impact of tax rate changes	(31	)	-		-
Regional Oil Sands System - loss on disposal of non-core assets	(7	)	-		-
Regional Oil Sands System - prior period adjustment	16		-		-
Regional Oil Sands System - make-up rights out-of-period adjustment	-		-		(37	)
Regional Oil Sands System - long-term contractual recovery
out-of-period adjustment, net	-		-		31
Seaway and Flanagan South Pipelines - make-up rights adjustment	(35	)	(25	)	-
Spearhead Pipeline - make-up rights adjustment	1		-		-
Spearhead Pipeline - changes in unrealized derivative fair value gains/(loss)	(1	)	1		-
Feeder Pipelines and Other - gain on sale of non-core assets	44		-		-
Feeder Pipelines and Other - make-up rights adjustment	(3	)	3		-
Feeder Pipelines and Other - project development costs	(5	)	(6	)	-
Feeder Pipelines and Other - impact of tax rate changes	(4	)	-		-
Earnings/(loss) attributable to common shareholders	(224	)	463		427

Liquids Pipelines adjusted earnings were $691 million in 2015 compared with adjusted earnings of $858 million in 2014 and $770 million in 2013. Liquids Pipelines adjusted earnings for the year ended December 31, 2015 are impacted by the effects of the transfer of interests in Southern Lights Pipeline in November 2014 and September 2015 and the transfer of Canadian Mainline and Regional Oil Sands System under the Canadian Restructuring Plan effective September 1, 2015. Following the transfers to the Fund Group, the results of these assets are no longer reported in the Liquids Pipelines segment, but are captured in the results of the Fund Group which are reported within Sponsored Investments.

Prior to the closing of the Canadian Restructuring Plan effective September 1, 2015, the Company continued to realize growth on Canadian Mainline primarily due to higher throughput that resulted from strong oil sands production in western Canada combined with strong downstream refinery demand, as well as successful efforts by the Company to optimize capacity and throughput and to enhance scheduling efficiency with shippers. These positive effects on Canadian Mainline were partially offset by a lower year-over-year average Canadian Mainline IJT Residual Benchmark Toll. In 2015, the Company benefitted from the full-year operation of Flanagan South and Seaway Pipeline Twin, which commenced in late 2014. Adjusted earnings from Regional Oil Sands System, however, decreased due to a reduction in contracted volumes on the Athabasca Mainline.

Additional details on items impacting Liquids Pipelines include:

·		Canadian Mainline earnings/(loss) for each period reflected changes in unrealized fair value 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 earnings/(loss) for 2015 and 2014 included depreciation and interest expenses charged to Line 9B while it was idled and undergoing a reversal as part of the Company’s Eastern Access initiative.
·		Canadian Mainline loss for 2015 included a write-off of a regulatory asset in respect of taxes resulting from the transfer of assets between entities under common control of Enbridge in conjunction with the Canadian Restructuring Plan.
·		Regional Oil Sands System earnings for each period included make-up rights adjustments to recognize revenue for certain long-term take-or-pay contracts rateably over the contract life. 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 earnings, 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 earnings for each period included charges, before insurance recoveries, related to the Line 37 crude oil release, which occurred in June 2013. Refer to Liquids Pipelines – Regional Oil Sands System – Line 37 Crude Oil Release.
·		Regional Oil Sands System earnings for 2015 and 2014 included insurance recoveries 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.
·		Regional Oil Sands System earnings for 2013 included an out-of-period, non-cash adjustment to defer revenues associated with make-up rights earned under certain long-term take-or-pay contracts.
·		Regional Oil Sands System earnings for 2013 included an out-of-period, non-cash adjustment to correct deferred income tax expense and to correct the rate at which deemed taxes are recovered under a long-term contract.
·		Earnings/(loss) for Canadian Mainline, Regional Oil Sands System and Feeder Pipelines and Other included the impact of a corporate tax rate change in the province of Alberta on opening deferred income tax balances.
·		Feeder Pipelines and Other earnings for 2015 and 2014 included certain business development costs related to Northern Gateway that are anticipated to be recovered over the life of the project.

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 Canadian Mainline assets and results are reported under the Sponsored Investments segment from the date of transfer. The Lakehead System is the portion of the mainline system in the United States that continues to be managed by Enbridge through its subsidiaries – see Sponsored Investments – Enbridge Energy Partners, L.P. and Enbridge Energy, Limited Partnership.

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. 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 earnings for year ended December 31, 2015 are impacted by the effect of the Canadian Restructuring Plan. Prior to September 1, 2015, the closing date of the Canadian Restructuring Plan, Canadian Mainline results were reflected in Liquids Pipelines. Following the close of the Canadian Restructuring Plan on September 1, 2015, the results of Canadian Mainline are no longer reported in the Liquids Pipelines segment, but are captured in the results of the Fund Group which are reported within Sponsored Investments – see Sponsored Investments – The Fund Group. For further details on the Canadian Restructuring Plan refer to Recent Developments – Sponsored Investments – The Fund Group – Canadian Restructuring Plan.

Canadian Mainline adjusted earnings were $395 million for the eight month period ended August 31, 2015 compared with $500 million for the year ended December 31, 2014. Prior to the closing of the Canadian Restructuring Plan on September 1, 2015, Canadian Mainline adjusted earnings increased compared with the corresponding 2014 periods. The period-over-period 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 third quarter 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. Other factors contributing to an increase in adjusted earnings were higher terminalling revenues and the impact of a stronger United States dollar as the IJT Benchmark Toll and its components are set in United States dollars. The majority of the Company’s foreign exchange risk on Canadian Mainline earnings is hedged; however, the average foreign exchange rate at which these revenues were hedged was higher during the eight month period ended August 31, 2015 compared with the same period in 2014. These trends continued into the month of September and in the fourth quarter of 2015, although the throughput impacts related to the upstream plant maintenance and shutdown of a midwest refinery noted above were alleviated towards the latter part of the fourth quarter of 2015. In addition, Canadian Mainline fourth quarter of 2015 adjusted earnings also reflected one month of revenues from Line 9B which was placed into service in December 2015. The Canadian Mainline adjusted earnings for the month of September and the fourth quarter of 2015 are reflected in the Fund Group, whereas adjusted earnings for the comparative 2014 periods were reflected in Liquids Pipelines.

Partially offsetting the positive factors noted above for the eight month period ended August 31, 2015 was a lower 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. Changes in the Canadian Mainline IJT Residual Benchmark Toll are inversely related to the Lakehead System Toll, which was higher due to the recovery of incremental costs associated with EEP’s growth projects. Also mitigating the impact of a lower Canadian Mainline IJT Residual Benchmark Toll were new surcharges related to system expansions, including a surcharge for the Edmonton to Hardisty Expansion pipeline completed in April 2015. Other factors which negatively impacted adjusted earnings were higher power costs associated with higher throughput, higher depreciation expense due to an increased asset base and higher interest expense resulting from higher outstanding debt to support increased business activities. These trends also continued into the month of September and in the fourth quarter of 2015.

Canadian Mainline adjusted earnings were $500 million for the year ended December 31, 2014 compared with $460 million for the year ended December 31, 2013. Adjusted earnings growth was primarily driven by higher throughput with several factors contributing to the increase including increased oil sands production, 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 and successful efforts by the Company to optimize capacity and throughput and to enhance scheduling efficiency with shippers. Other positive contributors to adjusted earnings included higher terminalling revenues, lower operating and administrative costs and lower income tax expense, which reflected current income taxes only and was lower due to higher available tax deductions.

Partially offsetting these positive impacts in 2014 was a lower year-over-year average Canadian Mainline IJT Residual Benchmark Toll, with its impact especially prominent in the fourth quarter of 2014. In the fourth quarter of 2014, the Canadian Mainline IJT Residual Benchmark Toll was US$1.53 per barrel compared with US$1.80 per barrel in the equivalent period of 2013. The decrease in the toll was a key contributor to lower adjusted earnings in the fourth quarter of 2014 compared with the same period of 2013. Also negatively impacting adjusted earnings were higher power costs associated with incremental throughput as well as higher depreciation from an increased asset base. Finally, Canadian Mainline adjusted earnings for 2014 were impacted by the absence of revenues from Line 9B, which was idled in late 2013, pending its reversal and expansion which was subsequently completed in late 2015.

Supplemental information on Canadian Mainline adjusted earnings for the years ended December 31, 2015, 2014 and 2013 is provided below.

Year ended December 31,	2015		2014		2013
(millions of Canadian dollars)
Revenues6	1,837		1,465		1,434
Expenses
Operating and administrative6	426		381		407
Power	224		160		122
Depreciation and amortization	295		270		244
	945		811		773
	892		654		661
Other income	3		11		3
Interest expense	(201	)	(162	)	(162	)
	694		503		502
Income taxes	(26	)	(3	)	(42	)
	668		500		460
Amounts attributable to the Fund Group within Sponsored Investments1	(273	)	-		-
Adjusted earnings - Liquids Pipelines1	395		500		460

Effective United States to Canadian dollar exchange rate2	1.102		1.016		0.999

December 31,		2015	2014	2013
(United States dollars per barrel)
IJT Benchmark Toll3		$4.07	$4.02	$3.98
Lakehead System Local Toll4		$2.44	$2.49	$2.18
Canadian Mainline IJT Residual Benchmark Toll5		$1.63	$1.53	$1.80
1	Effective September 1, 2015, the results of Canadian Mainline are reflected in adjusted earnings from the Fund Group within the Sponsored Investments segment, whereas results prior to September 1, 2015, are reflected in Liquids Pipelines adjusted earnings.
2	Inclusive of realized gains and losses on foreign exchange derivative financial instruments.
3	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.
4	The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective January 1, 2014, the Lakehead System Local Toll decreased from US$2.18 to US$2.17. 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 United States 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. Effective July 1, 2015, this toll increased to US$2.44.
5	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 January 1, 2014, this toll increased from US$1.80 to US$1.81. This toll increased to US$1.85 effective July 1, 2014 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.
6	In 2015, the Company commenced collecting, in its tolls, NEB mandated future abandonment costs from shippers. For the year ended December 31, 2015, approximately $38 million in revenue was recorded, but this amount was offset by a regulatory expense within operating and administrative expense. For further details, refer to Critical Accounting Estimates.

Throughput Volume1

		Q1	Q2	Q3	Q4	Full Year
2015		2,210	2,073	2,212	2,243	2,185
2014		1,904	1,968	2,039	2,066	1,995
2013		1,783	1,604	1,736	1,827	1,737
1	Throughput, presented in thousands of bpd, represents mainline deliveries ex-Gretna, Manitoba, which is made up of United States and eastern Canada deliveries originating from western Canada. For the year ended December 31, 2015, the results of Canadian Mainline are reflected in Liquids Pipeline from January 1, 2015 to August 31, 2015. Effective September 1, 2015, the results of Canadian Mainline are reflected in the Fund Group within the Sponsored Investments segment.

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 in late 2013 for reversal and expansion. The project was completed and the 300,000 bpd line was placed into service in December 2015 as part of the Company’s Eastern Access initiative – see Growth Projects – Commercially Secured Projects – Sponsored Investments – The Fund Group – Eastern Access. 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 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.

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.

Canadian Mainline income taxes reflect current income taxes only. Under the CTS, the Company retains the ability to recover deferred income taxes under an NEB order governing flow-through income tax treatment and, as such, an offsetting regulatory asset related to deferred income taxes is recognized as incurred. No other material regulatory assets or liabilities are recognized under the terms of the CTS.

REGIONAL OIL SANDS SYSTEM

Regional Oil Sands System includes three 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 70 kilometres (45 miles) south of Fort McMurray where the Waupisoo Pipeline initiates. Regional Oil Sands System also includes the Wood Buffalo Pipeline and Norealis Pipeline, each of which provides access for oil sands production from near Fort McMurray to the Cheecham Terminal. The recently completed Woodland Pipeline extension project further extended the Woodland Pipeline south from the Company’s Cheecham Terminal to its Edmonton Terminal. Regional Oil Sands System also includes a variety of other facilities such as the MacKay River, Christina Lake, Surmont, Long Lake and AOC laterals and related facilities. Regional Oil Sands System currently serves eight 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 Regional Oil Sands System assets and results are reported under the Sponsored Investments segment from the date of transfer.

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 after completion of a pipeline expansion in December 2013. 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.

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 some short-term variability dependent on the timing of when certain shippers’ commitments expire and commence.

Results of Operations

Regional Oil Sands System adjusted earnings for the year ended December 31, 2015 were $108 million compared with $181 million for the year ended December 31, 2014. The decrease in adjusted earnings was primarily due to the transfer of the Regional Oil Sands System to the Fund Group, within the Sponsored Investments segment. Following the close of the Canadian Restructuring Plan on September 1, 2015, the results of Regional Oil Sands System are no longer reported in the Liquids Pipelines segment, but are captured in the financial results of the Fund Group within Sponsored Investments – see Sponsored Investments – The Fund Group.

Prior to the closing of the Canadian Restructuring Plan on September 1, 2015, Regional Oil Sands System adjusted earnings were lower compared with the corresponding 2014 period and reflected a reduction in contracted volumes on the Athabasca Mainline, mitigated in part by higher uncommitted volumes on this pipeline. Higher depreciation expense from a larger asset base and higher interest expense also contributed to a decrease in period-over-period adjusted earnings. These negative effects were partially offset by higher earnings 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 as well as Norealis Pipeline which was completed in April 2014. These trends continued into September as well as in the fourth quarter of 2015, with higher earnings from assets placed into service in the third quarter of 2015 partially offset by higher depreciation and interest expenses related to these assets, as well as the continuing impacts of the reduction in contracted volumes on the Athabasca Mainline. The Regional Oil Sands System adjusted earnings for the month of September and the fourth quarter of 2015 are reflected in the Fund Group, whereas adjusted earnings for the comparative 2014 periods were reflected in Liquids Pipelines.

Regional Oil Sands System adjusted earnings for the year ended December 31, 2014 were $181 million compared with $170 million for the year ended December 31, 2013. Adjusted earnings growth in 2014 was primarily driven by contributions from the Norealis Pipeline which was completed in April 2014, higher throughput on the Athabasca Pipeline and higher capital expansion fee revenue from the Waupisoo Pipeline. Partially offsetting the increase in adjusted earnings were higher depreciation expense from a larger asset base and higher operating and administrative, interest and tax expenses from increased operational activities.

Line 37 Crude Oil Release

On June 22, 2013, Enbridge reported a release of light synthetic crude oil on its Line 37 pipeline approximately two kilometres north of Enbridge’s Cheecham Terminal. Line 37 connects facilities in the Long Lake area to the Cheecham Terminal. The Company estimated the volume of the release at approximately 1,300 barrels, 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 Line 37 on July 29, 2013 after finalization of geotechnical analysis.

As a precaution, on June 22, 2013, the Company shut down the pipelines that share a corridor with Line 37, including the Athabasca, Waupisoo, Wood Buffalo and Woodland pipelines. Following extensive engineering and geotechnical analysis, all of the lines except Woodland Pipeline were returned to service by July 19, 2013. The Woodland Pipeline had been in the process of line-fill at the time of the shutdown; line-fill activities were completed in the third quarter of 2013.

For the years ended December 31, 2015, 2014 and 2013, the Company’s earnings reflected remediation and long-term stabilization costs of approximately $5 million, $4 million and $56 million after-tax and before insurance recoveries, respectively, within Liquids Pipelines. 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.

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. Prior to the transfer of the Regional Oil Sands System to the Fund Group effective September 1, 2015, Enbridge recognized insurance recoveries of $9 million after-tax in connection with the Line 37 crude oil release within Liquids Pipelines, whereas in the fourth quarter of 2015, the Fund Group recognized insurance recoveries of $22 million ($13 million after-tax attributable to Enbridge) within Sponsored Investments. For the year ended December 31, 2014, insurance recoveries of $8 million after-tax were recognized in connection with the Line 37 crude oil release within Liquids Pipelines. On February 1, 2016, Enbridge was notified that the provincial government agency had completed and closed its investigation on this matter.

SEAWAY AND FLANAGAN SOUTH PIPELINES

Seaway and Flanagan South Pipelines include Enbridge’s 50% interest in Seaway Pipeline and whole ownership of Flanagan South.

Seaway Pipeline

In 2011, Enbridge acquired a 50% interest in the 1,078-kilometre (670-mile) 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 6.8 million barrels of crude oil tankage on the Texas Gulf Coast.

The flow direction of Seaway Pipeline was reversed in May 2012, enabling it to transport crude from the oversupplied hub in Cushing, Oklahoma to the Gulf Coast. Further pump station additions and modifications were completed in January 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 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.

Results of Operations

Seaway and Flanagan South Pipelines adjusted earnings for the year ended December 31, 2015 were $103 million compared with adjusted earnings of $74 million for the year ended December 31, 2014. The increase in adjusted earnings 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 and Flanagan South Pipelines 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. When committed shippers on Flanagan South are unable to fulfill their volume commitments due to apportionment, they are provided with temporary relief to make up those volumes during the course of their contracts or the apportioned volumes are added on to the end of the contract term.

Seaway and Flanagan South Pipelines adjusted earnings for the year ended December 31, 2014 were $74 million compared with adjusted earnings of $48 million for the year ended December 31, 2013. Higher adjusted earnings reflected the incremental earnings associated with first oil received on Flanagan South and Seaway Pipeline Twin in December 2014. Also positively impacting adjusted earnings were higher average tolls on Seaway Pipeline. Partially offsetting the increased adjusted earnings were higher operating expense and financing costs from an increased asset base.

Seaway Pipeline Regulatory Matter

Seaway Pipeline filed an application for market-based rates in December 2011. In relation to the original market-based rate application, FERC issued its decision rejecting Seaway Pipeline’s application for market-based rates in February 2014. In the Seaway Pipeline order, FERC also announced a new methodology 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 rate application. The FERC noticed the application in the Federal Register and in response 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 issued its decision setting the application for hearing. The case has been assigned to an ALJ, who held a scheduling conference on October 1, 2015, subsequent to which, evidence was filed on December 3, 2015. The scheduling order calls for a hearing to start on July 7, 2016 and an initial decision of the ALJ on December 1, 2016.

Since the FERC had not issued a ruling on the market-based rate application, Seaway Pipeline filed for initial rates in order to have rates in effect by the in-service date. The uncommitted rate on Seaway Pipeline was challenged by several shippers. In September 2013, a decision from an ALJ was released finding that the committed and uncommitted rates on Seaway Pipeline should be reduced to reflect the ALJ’s findings on the various cost of service inputs. Seaway Pipeline filed a brief with the FERC on October 15, 2013, challenging the ALJ’s decision and asking for expedited ruling by the FERC on the committed rates. In February 2014, the FERC issued its decision upholding its policy to honour contracts and ordered the ALJ to revise her decision accordingly.

On May 9, 2014, the ALJ issued an initial decision on remand reiterating her previous findings and did not change her decision. Briefings have concluded and the full record was sent to the FERC for its final decision, which was issued February 1, 2016. In its order, FERC again upholds the committed rates and reverses the ALJ’s holding that the committed rates should be reduced to cost-based levels. With respect to the uncommitted rates, FERC permits Seaway to include the full Enbridge purchase price (including goodwill) in rate base. FERC’s other cost-of-service rulings regarding the uncommitted rates are also largely favourable to Seaway.

A compliance filing calculating revised rates is due March 17, 2016.

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 March 2006 and an expansion was completed in May 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.

Results of Operations

Adjusted earnings for Spearhead Pipeline were $34 million for the year ended December 31, 2015 compared with $31 million for the year ended December 31, 2014. The increase in adjusted earnings reflected higher tariff rates and expiry of deficiency credits in the fourth quarter of 2015, as well as lower power costs. These positive factors were partially offset by lower throughput which was more prominent in the first nine months of 2015 due to upstream apportionment, refinery maintenance, unscheduled shutdown and power outages.

Adjusted earnings for Spearhead Pipeline were $31 million for each of the years ended December 31, 2014 and 2013. 2014 adjusted earnings reflected a combination of higher throughput and tolls, as well as lower pipeline integrity expenditures that were more prominent in 2013. These positive factors were offset by incremental power costs associated with higher throughput and by higher administrative expense.

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 on July 1, 2010. Prior to the close of the Canadian Restructuring Plan, 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 an ROE of 10%. The 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 the Class A Units of certain Enbridge subsidiaries that indirectly own the Canadian and Untied States segments of Southern Lights Pipeline (Southern Lights Class A units). The Southern Lights Class A units 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 Sponsored Investments – The Fund Group – The Fund Group 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 earnings for the year ended December 31, 2015 were $11 million compared with $49 million for the year ended December 31, 2014. The majority of the economic benefit derived from Southern Lights Pipeline was reflected in earnings from the Fund Group following the Fund Group’s November 2014 subscription and purchase of Southern Lights Class A units. The Class A units provide a defined cash flow stream from Southern Lights Pipeline. In addition, adjusted earnings for 2015 also reflected the effects of the transfer of Southern Lights Canada’s Class B units as discussed above.

Southern Lights Pipeline earnings were $49 million for each of the years ended December 31, 2014 and 2013, respectively. Earnings were comparable between the two fiscal years; however, due to offsetting factors. Higher recovery of negotiated depreciation rates in 2014 transportation tolls were offset by higher interest expense associated with the issuance of Class A units to the Fund Group.

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, transporting 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 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 delivers Bakken and other light sweet crude oil to Philadelphia area refineries, as well as business development costs related to Liquids Pipelines activities.

Results of Operations

Feeder Pipelines and Other adjusted earnings were $40 million for the year ended December 31, 2015 compared with $23 million for the year ended December 31, 2014. The increase in adjusted earnings 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 and contributions from Southern Access Extension which was placed into service in December 2015. Partially offsetting the increase in adjusted earnings were higher business development costs not eligible for capitalization in the first quarter of 2015, lower average tolls on Olympic Pipeline and higher property taxes relating to Toledo Pipeline in the third quarter of 2015.

Feeder Pipelines and Other adjusted earnings were $23 million for the year ended December 31, 2014 compared with $12 million for the year ended December 31, 2013. The increase in adjusted earnings in Feeder Pipelines and Other reflected higher tolls and throughput on the Toledo Pipeline, incremental earnings from Eddystone completed in April 2014, higher tankage revenues and lower business development costs not eligible for capitalization. Partially offsetting the increase in adjusted earnings were lower average tolls on Olympic.

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. 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. However, the long-term outlook for Canadian crude oil production indicates a growing source of potential supply of crude oil.

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 the Company, in 2014, Enbridge and EEP announced the $7.5 billion L3R Program. This project will not increase the overall capacity of the mainline system, but upon completion it 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.

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.

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 and other liquids pipelines are subject to the actions of various regulators, including the NEB and the 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 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.

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 and the United States 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. 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 Canadian Mainline 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.

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

	2015		2014	2013
(millions of Canadian dollars)
Enbridge Gas Distribution Inc. (EGD)	180		158	156
Other Gas Distribution and Storage	30		19	20
Adjusted earnings	210		177	176
EGD - colder than normal weather	11		36	9
EGD - changes in unrealized derivative fair value loss	(3	)	-	-
EGD - employee severance cost adjustment	4		-	-
EGD - gas transportation costs out-of-period adjustment	-		-	(56	)
Earnings attributable to common shareholders	222		213	129

Adjusted earnings from Gas Distribution were $210 million for the year ended December 31, 2015 compared with $177 million for the year end December 31, 2014 and $176 million for the year ended December 31, 2013. EGD 2015 and 2014 results reflected rates as established under EGD’s customized IR Plan. EGD generated higher adjusted earnings in 2015 primarily due to an increase in distribution charges that resulted from an increased asset base, as well as customer growth. In 2015, adjusted earnings from Other Gas Distribution and Storage reflected the absence of a contract loss that Enbridge Gas New Brunswick Inc. (EGNB) incurred in 2014.

Additional details on items impacting Gas Distribution earnings include:

· EGD earnings for 2013 reflected an out-of-period correction to gas transportation costs that had previously been deferred.

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 parts 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 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 requires allowed 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.

For the year ended December 31, 2015, EGD’s rates were set according to the OEB approved settlement agreement (April 2015) and the final rate order (May 2015). The rates approved as part of the 2015 rate application represented the second year of the Company’s customized IR Plan.

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, 2015 and 2014, EGD recognized $7 million and $12 million, respectively, as a return of revenues to customers in relation to the earnings sharing mechanism.

EGD’s 2013 rates were set pursuant to an OEB approved settlement agreement and decision (the 2013 Settlement) related to its 2013 cost of service rate application. The 2013 Settlement retained the previous deemed equity level but provided for an increase in the allowed ROE. The 2013 Settlement further retained the flow-through nature of the cost of natural gas supply and several other cost categories. There was no earnings sharing mechanism under the 2013 Settlement. The 2013 Settlement allowed EGD to recognize revenue and a corresponding regulatory asset relating to other postretirement benefit obligations (OPEB) as it established the right to recover previous OPEB costs of approximately $89 million ($63 million after-tax) over a 20-year time period commencing in 2013. The 2013 Settlement further provided for OPEB and pension costs, determined on an accrual basis, to be recovered in rates.

Results of Operations

EGD adjusted earnings for the year ended December 31, 2015 were $180 million compared with $158 million for the year ended December 31, 2014. While both years reflected rates as established under the customized IR Plan, the higher adjusted earnings in 2015 were primarily attributable to an increase in distribution charges that resulted from an increased asset base, as well as customer growth during the year in excess of expectations embedded in rates.

EGD adjusted earnings for the year ended December 31, 2014 were $158 million compared with $156 million for the year ended December 31, 2013. The slight increase in EGD year-over-year adjusted earnings reflected customer growth, lower employee related and other costs and the impact of the approved customized IR Plan. The customized IR Plan included a new approach for determining depreciation and future removal and site restoration reserves, which resulted in a lower depreciation expense for the year ended December 31, 2014. These positive effects were partially offset by reduced rates and the resumption of the earnings sharing mechanism under the customized IR Plan, as well as lower shared savings mechanism revenues.

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 12,000 customers and is regulated by the New Brunswick Energy and Utilities Board (EUB).

Results of Operations

Other Gas Distribution and Storage earnings were $30 million for the year ended December 31, 2015 compared with $19 million for the year ended December 31, 2014. The increase in earnings 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 earnings increased slightly in 2015 due to higher distribution revenues.

Other Gas Distribution and Storage earnings were $19 million for the year ended December 31, 2014 compared with $20 million for the year ended December 31, 2013. Lower earnings included a loss from EGNB related to the natural gas sale contract with the province of New Brunswick as noted above. Higher distribution volumes and higher rates that became effective in May 2014 partially offset the decreased earnings in EGNB.

Enbridge Gas New Brunswick Inc. – Regulatory Matters

In April 2012, the Company commenced an action against the Government of New Brunswick in the New Brunswick courts, seeking damages for breach of contract. The action seeks 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.

In May 2012, the Company also commenced a separate application to the New Brunswick courts to challenge elements of the Government’s rates and tariffs regulation, as it then existed. Ultimately, the Company was successful in defeating the part of the rates and tariffs regulation that capped rates according to a maximum revenue-to-cost ratio. Consequently, EGNB has been able to recover substantially all of its revenue requirement since August 2013, when the successful result of this legal challenge was first implemented into rates.

On February 4, 2014, EGNB commenced second action against the Government of New Brunswick in the New Brunswick courts. The action seeks 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.

There is no assurance that either of the two actions presently maintained by EGNB against the Province of New Brunswick will be successful or will result in any recovery.

BUSINESS RISKS

The risks identified below are specific to 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 by maintaining regular and transparent communication with regulators and intervenors on rate negotiations. The terms of rate negotiations are also reviewed by the Company’s legal, regulatory and finance teams. The approval of the five-year customized IR Plan in 2014 also provides a level of stability by having a longer-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. The above noted terms set out in the settlement agreement mitigate the Company’s risk to factors beyond management’s control.

Natural Gas Cost Risk

EGD 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.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

EARNINGS

	2015		2014		2013
(millions of Canadian dollars)
Aux Sable	(7	)	28		49
Energy Services	42		35		75
Alliance Pipeline US	-		41		43
Vector Pipeline	16		15		22
Canadian Midstream	41		23		12
Enbridge Offshore Pipelines (Offshore)	(2	)	(2	)	(2	)
Other	(1	)	(4	)	4
Adjusted earnings	89		136		203
Aux Sable - accrual for commercial arrangements	(19	)	-		-
Energy Services - changes in unrealized derivative fair value gains/(loss)	152		424		(206	)
Canadian Midstream - impact of tax rate changes	(3	)	-		-
Offshore - gain on sale of non-core assets	4		57		-
Other - changes in unrealized derivative fair value loss	-		-		(61	)
Other - impact of tax rate changes	(5	)	-		-
Earnings/(loss) attributable to common shareholders	218		617		(64	)

Adjusted earnings from Gas Pipelines, Processing and Energy Services were $89 million for the year ended December 31, 2015 compared with $136 million for the year ended December 31, 2014 and $203 million for the year ended December 31, 2013. Unfavourable market conditions in Aux Sable and absence of earnings from the United States portion of the Alliance Pipeline (Alliance Pipeline US) which was transferred to the Fund Group in November 2014 contributed to the lower adjusted earnings in 2015. Lower fractionation margins and the loss of a producer processing contract at the Palermo Conditioning Plant have contributed to lower Aux Sable earnings over the past two years. Aux Sable 2015 results were also negatively impacted by costs associated with feedstock supply. Partially offsetting the decrease in 2015 were higher take-or-pay fees on Canadian Midstream assets and higher contributions from Energy Services. Energy Services benefitted from more favourable tank management opportunities resulting from strong refinery demand for blended crude oil feedstock, partially offset by the effects of less favourable conditions which persisted over the past two years in certain markets accessed by committed transportation capacity involving unrecovered demand charges.

Additional details on items impacting Gas Pipelines, Processing and Energy Services earnings/(loss) include:

· Energy Services earnings/(loss) for each period reflected 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 the revaluation of inventory.

· Energy Services adjusted earnings for 2014 excluded a realized loss of $117 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 adjusted earnings for 2013 excluded a realized loss of $58 million incurred to close out derivative contracts intended to hedge forecasted Energy Services transactions which did not occur.

· Other loss for 2015 included the impact of a corporate tax rate change in the province of Alberta on opening deferred income tax balances.

· Other loss for 2013 reflected changes in unrealized fair value loss on the long-term power price derivative contracts acquired to hedge expected revenues and cash flows from Blackspring Ridge wind project.

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 a 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.

Aux Sable US sells its NGL production 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, 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 of the Aux Sable 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.

Aux Sable also owns facilities upstream of Alliance Pipeline that deliver 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; as well as Aux Sable Canada’s interests in the Montney area of British Columbia comprising 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 2015, the majority of capacity at the Palermo Gas Plant and on the Prairie Rose Pipeline was contracted to producers under take-or-pay contracts. Several producers’ contract commitments will decline over the next few years while certain producer contract commitments will continue through 2020 under long-term take-or-pay contracts or with life-of-lease reserve dedication. Additional 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 Environmental Protection Agency (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 believes to be an exceedance of currently permitted limits for Volatile Organic Material. Aux Sable received a second NFOV from the EPA in April 2015 in connection with this potential exceedance. Aux Sable is engaged in discussions with the EPA to evaluate the potential impact and ultimate resolution of these issues. Initial settlement proposal with the EPA confirms the amount will not be material.

Results of Operations

Aux Sable reported an adjusted loss of $7 million for the year ended December 31, 2015 compared with adjusted earnings of $28 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 year-over-year decreases in adjusted earnings.

Aux Sable adjusted earnings for the year ended December 31, 2014 were $28 million compared with adjusted earnings of $49 million for the year ended December 31, 2013. Aux Sable earnings reflected lower fractionation margins which decreased contributions from the upside sharing mechanism, partially offset by an increase in propane volumes produced at the Channahon Plant. Lower volumes at upstream processing plants and higher administrative expense also had a negative impact on Aux Sable earnings.

Aux Sable Feedstock Supply

Aux Sable secures NGL feedstock for its Channahon Plant through Rich Gas Premium (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. RGP contract volumes increased as of December 1, 2015, following the termination of essentially all of Alliance Pipeline’s initial long-term transportation contracts. Effective December 1, 2015, producers have 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 (ATP), notionally located on the Canadian portion of the Alliance Pipeline system. Aux Sable purchases RGP gas volumes delivered to ATP 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 Alliance Pipeline Recontracting, refer to Sponsored Investments – The Fund Group – Alliance Pipeline Recontracting.

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.

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.

ENERGY SERVICES

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. 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

Energy Services adjusted earnings were $42 million for the year ended December 31, 2015 compared with adjusted earnings of $35 million for the year ended December 31, 2014. Higher earnings in 2015 reflected strong refinery demand for blended crude oil feedstock leading to more favourable tank management opportunities in the first half of 2015. Also favourably impacting year-over-year adjusted earnings was the absence of losses realized in the first quarter of 2014 on certain financial contracts as discussed below.

The favourable tank management opportunities experienced in the first half of 2015 eroded in the second half of the year due to a reduction in refinery demand for blended crude oil feedstock and an increase in offshore crude supply in the Gulf Coast. The lack of favourable tank management opportunities together with the effects of less favourable conditions in certain markets accessed by committed transportation capacity involving unrecovered demand charges, resulted in an adjusted loss in the fourth quarter of 2015. Adjusted earnings from Energy Services are dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

Energy Services adjusted earnings were $35 million for the year ended December 31, 2014 compared with $75 million for the year ended December 31, 2013. Adjusted earnings decreased in 2014 compared with a very strong 2013 due to narrowing location spreads and less favourable conditions in certain markets accessed by committed transportation capacity, combined with associated unrecovered demand charges. Additionally, the 2014 adjusted earnings reflected 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. Partially offsetting the decrease in adjusted earnings in 2014 were more favourable conditions in certain markets in the fourth quarter of 2014 that gave rise to wider location and crude grade differentials and enabled Energy Services to capture more profitable margin and tank management arbitrage opportunities. Due in large part to the continued positive effects of these arbitrage opportunities, Energy Services 2014 fourth quarter adjusted earnings increased compared with the equivalent 2013 period which helped to partially offset the decrease in adjusted earnings experienced during the first nine months of the year. Also positively contributing to adjusted earnings were favourable natural gas location differentials caused by abnormal winter weather conditions during the first quarter of 2014.

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 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, including 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.

ALLIANCE PIPELINE US

In November 2014, Enbridge’s 50% ownership of the Alliance Pipeline US was transferred to the Fund Group with earnings contributions from Alliance Pipeline US prospectively reflected within the Sponsored Investments section effective November 7, 2014. Refer to Sponsored Investments – The Fund Group – Drop Down Transaction for details of the transfer. Effective November 7, 2014, the Fund Group owns 50% of Alliance Pipeline US along with its previous 50% ownership of the Canadian portion of the Alliance Pipeline (Alliance Pipeline Canada). For the Alliance Pipeline US asset overview, refer to Sponsored Investments – The Fund Group – Alliance Pipeline. For business risks specific to the Alliance Pipeline refer to Sponsored Investments – The Fund Group – Business Risks – Alliance Pipeline.

Results of Operations

The absence of Alliance Pipeline US earnings for the year ended December 31, 2015 reflected the transfer of Alliance Pipeline US to the Fund Group in November 2014.

Alliance Pipeline US earnings were $41 million for the year ended December 31, 2014 compared with earnings of $43 million for the year ended December 31, 2013. The decrease in Alliance Pipeline US earnings reflected the impact of the transfer of Alliance Pipeline US to the Fund Group in November 2014 and the corresponding absence of earnings. Prior to November 7, 2014, the date of the transfer, Alliance Pipeline US earnings increased compared with the equivalent 2013 period and reflected an increase in depreciation expense recovered in tolls, as well as earnings from the Tioga Lateral pipeline which was placed into service in September 2013.

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 billion cubic feet per day (bcf/d) and in 2015 it operated at or near capacity. The Company provides operating services to and holds a 60% joint venture interest in Vector.

Results of Operations

Vector earnings of $16 million for the year ended December 31, 2015 were comparable with earnings of $15 million for the year ended December 31, 2014. The positive effects of lower operating expenses and lower interest costs in 2015 due to debt repayment were offset by lower year-over-year transportation revenues as unusually high demand for natural gas transport was experienced in 2014 as discussed below.

Vector earnings were $15 million for the year ended December 31, 2014 compared with earnings of $22 million for the year ended December 31, 2013. The year-over-year decrease in Vector earnings reflected lower depreciation expense recognized in tolls, partially offset by higher revenues due to increased demand for natural gas during abnormal winter weather conditions experienced in the first quarter of 2014.

Transportation Contracts

Vector’s total long haul capacity was 84% contracted under firm service agreements at December 31, 2015. Approximately 27% of long haul capacity is through firm negotiated rate transportation contracts with shippers and approved by the FERC, while the remaining firm service contracts are sold at market rates.

In December 2015, shippers under negotiated rate transportation contracts which represent 20% of the system’s long haul capacity elected to extend their commitments through December 1, 2019 and preserve the option to extend their contracts on an annual basis. Vector is entitled to additional compensation from negotiated rate transportation shippers that terminate their contracts prior to the November 30, 2020 expiry date.

In late 2014 and early 2015, Vector signed precedent agreements with both the proposed NEXUS Pipeline and Energy Transfer Partners L.P.’s Rover Pipeline project, to provide transportation service to the Dawn natural gas market hub. Both projects are in the development stage and are subject to FERC approval. These pipeline projects are proposed to enter service during the second half of 2017.

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 2015, the FERC-approved maximum tariff rates included an underlying weighted average after-tax ROE component of 11.2%. 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 2015, maximum tolls include an ROE component of 10.5% 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. For risks specific to Alliance Pipeline refer to Sponsored Investments – The Fund Group – Business Risks – Alliance Pipeline.

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 two proposed pipeline projects that will extend back to the Marcellus/Utica supply basin. These arrangements, proposed to commence in 2017, will effectively fill all available delivery capacity from current contract roll-offs scheduled through 2019. Current firm service contracts that amount to approximately 52% of long haul capacity are scheduled to expire during 2016 and 2017.

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, in 2017, Vector is expected to commence firm service transport based on precedent agreements in place with 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.

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 (PHMSA) 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.

CANADIAN MIDSTREAM

At December 31, 2015, Canadian Midstream consisted of the Company’s 71% investment 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 investments in the Pipestone and Sexsmith gathering systems (together, Pipestone and Sexsmith). The Company has a 100% interest in Pipestone and varying interests (55% to 100%) in Sexsmith and its related sour gas gathering, compression and NGL handling facilities, located in the Peace River Arch (PRA) region of northwest Alberta. The Company is the operator of 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.

Phase 1 of Cabin is currently 98% completed. Cabin producers are expected to request the Company to commission and start-up Phase 1 once 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. Construction of Pipestone and Sexsmith and related facilities were completed in 2014.

In January 2016, the Company reached agreement with Murphy Oil for the purchase of the Tupper Plants within the Montney shale play in northeastern British Columbia, as described under Growth Projects – Commercially Secured Projects. The Tupper Plants, which are currently operating, are designed to process low H2S natural gas and remove a modest level of NGL in order to meet downstream natural gas pipeline specifications. The $0.5 billion transaction is anticipated to close by the second quarter of 2016, following required regulatory approvals. Enbridge will be the operator of the facilities and will provide gas processing services to area producers and to Murphy Oil under a 20-year take-or-pay contract with an option to extend the contract.

Results of Operations

Canadian Midstream earnings were $41 million for the year ended December 31, 2015 compared with earnings of $23 million for the year ended December 31, 2014. Higher earnings reflected an increase in take-or-pay fees on the Company’s investment in Cabin, Pipestone and Sexsmith. Pipestone earnings also increased as a result of higher volumes that exceeded take-or-pay levels and due to full year of incremental earnings from the final phase placed into service in June 2014.

Canadian Midstream earnings were $23 million for the year ended December 31, 2014 compared with earnings of $12 million for the year ended December 31, 2013. The increase in earnings reflected higher fees earned from the Company’s investments in Cabin, Pipestone and Sexsmith. Pipestone earnings were higher due to incremental earnings from the final phase placed into service in 2014 and higher volumes that exceeded take-or-pay levels.

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

Pipestone and Sexsmith are located within the liquids-rich PRA region which has seen significant development by area producers. In 2015, throughput volumes exceeded take-or-pay levels.

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.

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.

ENBRIDGE OFFSHORE PIPELINES

Offshore is comprised of 11 active natural gas gathering and FERC-regulated transmission pipelines and one active oil pipeline with a capacity of 60,000 bpd, in four major corridors in the Gulf of Mexico, extending to deepwater developments. These pipelines include almost 2,100 kilometres (1,300 miles) of underwater pipe and onshore facilities with total capacity of approximately 6.5 bcf/d. Offshore currently moves approximately 45% of total offshore gas production and 55% of deepwater gas production through its systems in the Gulf of Mexico.

Results of Operations

Offshore adjusted loss was $2 million for each of the years ended December 31, 2015, 2014 and 2013. Offshore adjusted losses for each year reflected persistent weak gas volumes due to decreased production in the Gulf of Mexico. Offshore adjusted losses for 2015 and 2014 also reflected the absence of earnings from the disposals of certain non-core assets that were finalized in March and November 2014, respectively. For the year ended December 31, 2015, Offshore also incurred losses from equity investments in certain joint venture pipelines. Partially offsetting these negative effects in 2015 were earnings from the Jack St. Malo portion of WRGGS that was completed in December 2014.

For the year ended December 31, 2014, Offshore adjusted losses were partially offset by incremental earnings from the completion of the Jack St. Malo portion of the WRGGS in December 2014 and cost savings achieved from the Company’s decision not to renew windstorm insurance coverage effective May 2013.

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 (MDQ) 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 MDQ schedule to match current delivery expectations. The majority of long-term transport rates are market-based, 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, Venice, 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 reach 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 earnings. 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 and availability of insurance coverage. On May 1, 2013, the Company elected not to renew windstorm coverage on its Offshore asset portfolio. The Company expects to reassess the market for windstorm coverage and revisit the possible purchase of coverage in future years as the Company’s portfolio of Offshore assets is expected to increase. Enbridge facilities are engineered to withstand hurricane forces and constant monitoring of weather allows for timely evacuation of personnel and shutdown of facilities; however, damages to assets or injuries to personnel may still occur.

OTHER

Prior to September 1, 2015, the closing date of the Canadian Restructuring Plan, Other included Lac Alfred, Massif du Sud, Blackspring Ridge and Saint Robert Bellarmin wind projects. Following the close of the Canadian Restructuring Plan on September 1, 2015, Other includes approximately 700 MW of net renewable power generating capacity out of the net enterprise-wide portfolio of nearly 2,000 MW. The balance of the portfolio is held by the Fund Group and earnings contributions from these assets, net of noncontrolling interests, are reflected within Sponsored Investments from the date the assets were transferred to the Fund Group. Also included in Other is the Montana-Alberta Tie-Line (MATL), the Company’s first power transmission asset.

Results of Operations

Adjusted loss from Other was $1 million for the year ended December 31, 2015 compared with an adjusted loss of $4 million for the year ended December 31, 2014. The 2015 adjusted loss from Other is impacted by the effects of the Canadian Restructuring Plan noted above. Following the closing of the Canadian Restructuring Plan on September 1, 2015, the results of the wind projects listed above are no longer reported in the Gas Pipelines, Processing and Energy Services segment, but are captured in the results of the Fund Group within Sponsored Investments – see Sponsored Investments – The Fund Group. For further details on the Canadian Restructuring Plan refer to Canadian Restructuring Plan.

Prior to September 1, 2015, adjusted earnings from Other increased compared with the corresponding 2014 period. The period-over-period increase reflected contributions from new wind farms including the Wildcat and Magic Valley wind farms acquired at the end of 2014 and incremental earnings 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 as discussed below, partially offset by higher business development costs not eligible for capitalization within Other. This trend continued into the month of September 2015 and the fourth quarter of 2015; however, adjusted earnings for these periods from the wind projects noted above, as part of the Canadian Restructuring Plan, were reflected in the Fund Group, whereas adjusted earnings for the corresponding 2014 periods were reflected in Gas Pipelines, Processing and Energy Services.

Adjusted loss from Other was $4 million for the year ended December 31, 2014 compared with adjusted earnings of $4 million for the year ended December 31, 2013. The decrease in adjusted earnings reflected lower southbound revenues on MATL combined with its higher depreciation expense and financing costs and higher business development costs not eligible for capitalization within Other. Partially offsetting the decrease in adjusted earnings was the positive impact of new wind farms placed into service in the prior years.

Lac Alfred and Massif du Sud Wind Projects

In September 2014, the Company entered into an agreement to purchase additional interests in the 300- MW Lac Alfred and the 150-MW Massif du Sud from existing partner, EDF EN Canada Inc. Under the agreement, Enbridge invested approximately $225 million to acquire an additional 17.5% interest in Lac Alfred and an additional 30% interest in Massif du Sud. The Lac Alfred transaction closed in October 2014, upon which Enbridge held a 67.5% interest in Lac Alfred. The Massif du Sud transaction closed in December 2014, upon which Enbridge held an 80% interest in Massif du Sud. As described above, effective September 1, 2015, Lac Alfred and Massif du Sud were transferred to the Fund Group under the Canadian Restructuring Plan.

SPONSORED INVESTMENTS

EARNINGS

	2015		2014		2013
(millions of Canadian dollars)
The Fund Group	509		125		110
Enbridge Energy Partners, L.P. (EEP)	231		197		165
Enbridge Energy, Limited Partnership (EELP)	119		107		38
Adjusted earnings	859		429		313
The Fund Group - make-up rights adjustment	(3	)	-		-
The Fund Group - changes in unrealized derivative fair value gains/(loss)	(174	)	3		-
The Fund Group - unrealized intercompany foreign exchange gains	43		-		-
The Fund Group - drop down transaction costs	(3	)	(2	)	-
The Fund Group - gain on sale	5		-		-
The Fund Group - impact of tax rate changes	(6	)	-		-
The Fund Group - write-down of regulatory balances	(3	)	-		-
The Fund Group - prior period adjustment	(16	)	-		-
The Fund Group - employee severance costs	(10	)	-		-
The Fund Group - Line 9B costs incurred during reversal	(1	)	-		-
The Fund Group - leak insurance recoveries	13		-		-
EEP - transfer of contracts	(1	)	-		-
EEP - changes in unrealized derivative fair value gains/(loss)	(6	)	5		(6	)
EEP - make-up rights adjustment	1		(1	)	-
EEP - goodwill impairment loss	(167	)	-		-
EEP - asset impairment loss	(11	)	(2	)	-
EEP - employee severance costs	-		(1	)	-
EEP - leak insurance recoveries	-		-		6
EEP - tax rate differences/changes	-		-		(3	)
EEP - valuation allowance on deferred income tax assets	(32	)	-		-
EEP - leak remediation costs	-		(12	)	(44	)
EEP - gain on sale of non-core assets	-		-		2
EEP - hydrostatic testing	(9	)	-		-
Earnings attributable to common shareholders	479		419		268

Adjusted earnings from Sponsored Investments were $859 million for the year ended December 31, 2015 compared with $429 million for the year ended December 31, 2014 and $313 million for the year ended December 31, 2013. Within the Fund Group, the material increase in adjusted earnings in 2015 is largely attributable to the transfer of the Canadian liquids business and certain Canadian renewable energy assets from Enbridge, effective September 1, 2015, the closing date of the Canadian Restructuring Plan. 2015 Fund Group adjusted earnings also reflect earnings from natural gas and diluent pipeline interests transferred by Enbridge to the Fund Group in November 2014. The increase in EEP’s adjusted earnings reflected higher throughput and tolls in EEP’s liquids business, including contributions from new assets placed into service in 2014 and 2015 and incremental earnings from the transfer of EELP’s remaining 66.7% interest in Alberta Clipper to EEP on January 2, 2015. Enbridge also benefitted from the completion of new assets placed into service in 2014 and 2015 through its 75% interest in EELP, partially offset by the absence of earnings from Alberta Clipper arising from the transfer noted above.

Additional details on items impacting Sponsored Investments include:

·	The Fund Group earnings for 2015 reflected changes in unrealized fair value losses primarily on derivative financial instruments used to risk manage exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices.

·	The Fund Group earnings for 2015 included employee severance costs in relation to Enbridge’s enterprise-wide reduction of workforce.

·	The Fund Group earnings for 2015 included the impact of a corporate tax rate change in the province of Alberta on opening deferred income tax balances.

·	The Fund Group earnings for 2015 included insurance recoveries 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.

·	EEP earnings for 2015 included a goodwill impairment charge related to EEP’s 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 EEP’s natural gas and NGL systems.

·	EEP earnings for 2015 reflected an asset impairment charge of US$63 million ($11 million after-tax attributable to Enbridge) related to EEP’s Berthold rail facility due to contracts that have not been renewed beyond 2016.

·	EEP earnings for 2014 and 2013 included charges related to estimated costs, before insurance recoveries, associated with the Line 6B crude oil release. Refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – Line 6B Crude Oil Release.

·	Earnings from EEP for 2014 included employee severance costs triggered by redundancies in EEP’s natural gas and NGL businesses.

·	EEP earnings for 2013 included insurance recoveries associated with the Line 6B crude oil release. Refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – Line 6B Crude Oil Release.

THE FUND GROUP

The Fund Group comprises the Fund, ECT, EIPLP and the subsidiaries of EIPLP. The Fund Group’s primary operations include three core businesses: liquids pipelines transportation and storage (Liquids Transportation and Storage), a natural gas transmission business through its 50% interest in Alliance Pipeline System (Gas Pipelines) and renewable power generation assets (Green Power). Effective September 1, 2015, under the Canadian Restructuring Plan, Enbridge transferred to the Fund Group its Canadian Liquids Pipelines business, comprised of the Canadian Mainline, Regional Oil Sands System, the Canadian portion of the Southern Lights Pipeline and certain residual rights and/or obligations relating to certain terminal and storage assets. For an overview of the Canadian Mainline, Regional Oil Sands System and Southern Lights Pipelines, refer to Liquids Pipelines. Enbridge also transferred to the Fund Group certain Canadian renewable energy assets – refer to Gas Pipelines, Processing and Energy Services.

The liquids pipelines assets transferred under the Canadian Restructuring Plan are included the Fund Group’s Liquids Transportation and Storage business effective September 1, 2015. Liquids Transportation and Storage business also operates a crude oil gathering system and trunkline pipeline in southern Saskatchewan and southwestern Manitoba, connecting to Enbridge’s mainline system at Cromer, Manitoba (the Saskatchewan System). In addition, Liquids Transportation and Storage includes the Canadian portion of the Bakken Expansion Pipeline, an interest acquired in Southern Lights Pipeline in November 2014, as well as the Hardisty Contract Terminals and Hardisty Storage Caverns located near Hardisty, Alberta.

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 bcf/d and 1.325 bcf/d, respectively. The Fund Group owns 50% of Alliance Pipeline Canada and 50% of Alliance Pipeline US. 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.

Within Green Power, the Fund Group had interests in over 500 MW of net renewable and alternative power generation capability prior to the closing of the Canadian Restructuring Plan. Following the transfer of additional renewable energy assets from Enbridge under the Canadian Restructuring Plan, Green Power’s net renewable and alternative power generation capability increased to an approximately 1,050 MW at December 31, 2015.

The Fund Group Drop Down Transaction

In November 2014, the Fund Group completed the acquisition of Enbridge’s 50% interest in Alliance Pipeline US and the subscription for and purchase of Class A units of Enbridge’s subsidiaries that indirectly own the Canadian and United States segments of the Southern Lights Pipeline. The Class A units, which are non-voting and do not confer any governance or ownership rights in Southern Lights Pipeline, will 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 (Bridge 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 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. Enbridge’s overall economic interest in the Fund Group was reduced from 67.3% to 66.4% upon completion of the transaction. At the time of the transaction, the Fund Group previously owned a 50% investment in Alliance Pipeline Canada.

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.

Results of Operations

Adjusted earnings for the Fund Group for the year ended December 31, 2015 were $509 million compared with $125 million for the year ended December 31, 2014. The significant increase in adjusted earnings is largely attributable to the transfer of the Canadian liquids business and certain Canadian renewable energy assets from Enbridge as well as Enbridge’s overall economic interest in the Fund Group, which increased to 91.9% on September 1, 2015, following the closing of the Canadian Restructuring Plan. For further discussion on the Canadian Restructuring Plan refer to Canadian Restructuring Plan. Enbridge’s economic interest subsequently decreased to 89.2% upon completion of ENF’s $700 million common share issuance on November 6, 2015.

Adjusted earnings from assets transferred under the Canadian Restructuring Plan were impacted by the same reasons as discussed in the Results of Operations sections of these assets within Liquids Pipelines and Gas Pipelines, Processing and Energy Services segments. Also positively impacting adjusted earnings from the Fund Group for the year ended December 31, 2015 were earnings from natural gas and diluent pipeline interests transferred by Enbridge to the Fund Group in the Fund Group Drop Down Transaction in November 2014. Partially offsetting the increase in adjusted earnings were higher financing costs associated with debt raised to acquire the natural gas and diluent pipeline interests, as well as higher income taxes.

Adjusted earnings for the Fund Group for the year ended December 31, 2014 were $125 million compared with $110 million for the year ended December 31, 2013. The increase in adjusted earnings reflects the incremental earnings from Enbridge’s transfer of natural gas and diluent pipeline interests to the Fund Group in November 2014, as well as strong performance from the Fund Group’s liquids business. Partially offsetting the increase in adjusted earnings were lower wind resources across several of the Fund Group’s wind farms and higher interest expense associated with an increase in external debt issued in 2014 to support the acquisition of the natural gas and diluent pipeline interests. Finally, adjusted earnings in 2014 were also positively impacted by higher preferred unit distributions received from the Fund Group.

Westspur Settlement

On April 1, 2013, the Fund Group announced it concluded a settlement (the Settlement) with a group of shippers resulting in new tolls on the Westspur System. At the request of certain shippers that did not execute the Settlement, the NEB did not remove the interim status from the historical tolls and made the new tolls interim as well. A modified agreement was subsequently entered into with substantially all of the shippers, and such shippers requested the NEB make both the historical tolls and the new tolls (collectively, the Tolls) final. On February 6, 2014, the NEB ordered the Tolls final.

The Settlement established a toll methodology for an initial term of five years, with additional one year renewal terms unless otherwise terminated. Pursuant to the Settlement, the Tolls on the Westspur System will be fixed and increased annually with reference to an inflation index, subject to throughput remaining within a prescribed volume band close to volumes recently transported on the Westspur System. The Settlement resulted in the discontinuance of rate-regulated accounting for the Westspur System and the Fund Group recorded an after-tax write-down of approximately $12 million ($4 million after-tax attributable to Enbridge) in the first quarter of 2013 related to a deferred regulatory asset that will not be collected under the terms of the Settlement.

Alliance Pipeline Recontracting

In 2013, Alliance Pipeline announced a new services framework and the related tolls and tariff provisions required to implement the new services (collectively, New Services Framework). On June 30, 2015 and July 9, 2015, Alliance Pipeline received regulatory approval from the FERC and the NEB, for the United States and Canadian segments of the pipeline, respectively, for the New Services Framework. Shipments under the New Services Framework commenced December 1, 2015. As part of its acceptance of Alliance Pipeline US’ New Services Framework, the FERC 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. The negotiated reservation rates contained in the Precedent Agreements were converted into negotiated rate transportation contracts as part of the New Services Framework and will not be part of this hearing. 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. Alliance Pipeline has successfully re-contracted its annual firm service capacity with an average contract length of approximately five years.

Pursuant to the New Services Framework, Alliance Pipeline retains exposure to potential variability in certain future costs and market based revenues generated from services provided beyond annual firm transport service. 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 and a derecognition of regulatory balances as at June 30, 2015 was required. The Fund Group recorded an after-tax write-down of approximately $10 million ($3 million after-tax attributable to Enbridge) during the second quarter of 2015.

BUSINESS RISKS

The risks identified below are specific to the Fund Group’s three core businesses: Liquids Transportation and Storage; Alliance Pipeline; and Green Power. For business risks related to the Canadian Mainline and Regional Oil Sands System, refer to Liquids Pipelines – Business Risks. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks.

Liquids Transportation and Storage

Asset Utilization

Asset utilization risk for the Fund Group’s liquids business shares similar risk characteristics to Liquids Pipelines as changing market fundamentals, capacity bottlenecks, including insufficient capacity downstream on the Canadian Mainline, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of the Fund Group’s assets. The Fund Group is also exposed to throughput risk under certain tolling agreements applicable to the Saskatchewan System assets.

The Fund Group seeks to mitigate utilization risks within its control, including working with the shipper community on its tolling agreements. Additionally, volume risk is somewhat mitigated for the Westspur System due to the fact that toll surcharges or discounts will be applied should throughput increase or decrease on a sustained basis outside a pre-defined band set as defined in the agreement.

Competition

Liquids Transportation and Storage, including the Saskatchewan System, faces competition in pipeline transportation from other pipelines as well as other forms of transportation, most notably rail. These alternative transportation options could charge rates or provide service to locations that result in greater netbacks for shippers, thereby reducing shipments on the Saskatchewan System or resulting in pressure to reduce tolls. The Saskatchewan System’s right-of-way and expansion efforts provide a competitive advantage.

Operational and Economic Regulation

Regulatory scrutiny over the integrity of the Fund Group’s assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on the Fund Group’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 Fund Group.

In relation to economic regulations, certain pipelines within the Saskatchewan System are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings and the success of expansion projects. Delays in regulatory approvals could result in cost escalations and construction delays. Changes in regulation, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could adversely affect the results of operations of the Fund Group and could adversely impact the timing and amount of recovery or settlement of regulatory balances.

The Company believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers. 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.

Alliance Pipeline

Asset Utilization

Currently, natural gas pipeline capacity out of the WCSB exceeds supply. Alliance Pipeline to date has been relatively unaffected by the excess supply environment as the Alliance Pipeline was successfully recontracted. Further, Alliance Pipeline is well positioned to deliver incremental liquids-rich gas production from developments in the Montney, Duvernay and Bakken regions to large natural gas markets and, following extraction and fractionation at the Aux Sable NGL extraction and fractionation plant, to deliver NGL to growing 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 the 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 the Alliance Pipeline. The ability of the 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.

Green Power

Asset Utilization

Earnings from Green Power 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 projects are predicted using long-term historical data, wind and solar resources will be 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 facilities could lead to decreased earnings for the Company. Additionally, inefficiencies or interruptions of Green Power facilities due to operational disturbances or outages 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 assets is also often sold to a single counterparty under PPA or other long-term pricing arrangements. In this respect, the performance of the Green Power assets is dependent on each counterparty performing its contractual obligations under the PPA or pricing arrangement applicable to it.

Competition

The Fund Group’s Green Power assets operate in the Canadian power market, which is subject to competition and the supply and demand balance for power in the provinces 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.

ENBRIDGE ENERGY PARTNERS, L.P.

EEP owns and operates crude oil and liquid petroleum transportation and storage assets; natural gas and NGL gathering, treating, processing, transportation assets; and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Canadian Mainline in the United States, the Mid-Continent Crude Oil System consisting of an interstate crude oil pipeline and storage facilities, a crude oil gathering system and interstate pipeline system in North Dakota and natural gas assets located primarily in Texas. Subsidiaries of Enbridge provide services to EEP in connection with the operation of its liquids assets, including the Lakehead System.

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, 2015, Enbridge’s economic interest in EEP was 35.7% (2014 - 33.7%; 2013 - 20.6%). The Company’s average economic interest in EEP during 2015 was 36.0% (2014 - 27.3%; 2013 - 21.1%). The increase in Enbridge’s economic interest in EEP largely reflected the impact of the restructuring of EEP’s equity in 2014 as discussed below. Additionally, Enbridge also holds a US$1.2 billion investment in EEP preferred units. For further discussion, refer to Sponsored Investments – Enbridge Energy Partners, L.P. – EEP Preferred Unit Private Placement and Joint Funding Option Exercise.

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% general partner (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 with the objective of enhancing the economics of EEP’s investment projects and growth opportunities, while at the same time re-establishing EEP as a strong sponsored vehicle and as an effective source of funding for Enbridge via future asset monetization.

Effective July 1, 2014, Enbridge Energy Company, Inc. (EECI), 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 (IDU) (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 IDU is 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

EEP makes quarterly distributions of its available cash to its common unitholders. Under the Partnership Agreement, EECI as GP receives incremental incentive cash distributions, which represent incentive income on the portion of cash distributions (on a per unit basis) that exceed certain target thresholds. Distributions to common unitholders and the GP are made as follows:

	Unitholders including Enbridge	GP Interest
Quarterly cash distributions per unit:
Up to US$0.5345 per unit	98%	2%
Target - cash distributions over US$0.5345 per unit	75%	25%

Prior to the Equity Restructuring, distributions to common unitholders and the GP were made on the basis of the following target thresholds:

	Unitholders including Enbridge	GP Interest
Quarterly cash distributions per unit:
Up to US$0.2950 per unit	98%	2%
First target - US$0.2950 per unit up to $0.3500 per unit	85%	15%
Second target - US$0.3500 per unit up to $0.4950 per unit	75%	25%
Over second target - cash distributions greater than US$0.4950 per unit	50%	50%

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 further 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 Sponsored Investments – Enbridge Energy Partners, L.P. – Alberta Clipper Drop Down.

In 2015, Enbridge received from EEP, incentive distributions of US$19 million (2014 - US$39 million; 2013 - US$130 million). Also in 2015, Enbridge received distributions of US$195 million from Class D units (2014 - US$108 million) and Class E units which were issued under the Equity Restructuring and Alberta Clipper Drop Down transactions.

Results of Operations

Adjusted earnings from EEP were $231 million for the year ended December 31, 2015 compared with $197 million for the year ended December 31, 2014. The adjusted earnings increase reflected higher throughput and tolls in EEP’s liquids business, 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 addition, EEP adjusted earnings reflected incremental earnings from the transfer on January 2, 2015 of the remaining 66.7% interest in Alberta Clipper previously held by Enbridge through EELP. Partially offsetting the increase in adjusted earnings in EEP’s liquids business were higher operating and administrative costs, incremental power costs associated with higher throughput and higher depreciation expense from an increased asset base. Also contributing to higher earnings in 2015 were distributions from Class D units and IDU which were issued to Enbridge in July 2014 under the equity restructuring transaction described above and from Class E units which were issued in January 2015 in connection with the transfer of Alberta Clipper. Finally, the 2015 results reflected lower volumes within EEP’s natural gas and NGL businesses primarily as a result of reduced drilling programs by producers. EEP holds its natural gas and NGL businesses directly and indirectly through its partially-owned subsidiary, MEP.

Adjusted earnings from EEP were $197 million for the year ended December 31, 2014 compared with $165 million for the year ended December 31, 2013. Within EEP’s liquids business, adjusted earnings increased primarily as a result of new assets placed into service during 2013 and 2014, combined with higher throughput and tolls on its major liquids pipelines. New assets placed into service included the replacement and expansion of Line 6B as part of Enbridge and EEP’s Eastern Access initiative, as well as the Line 6B 75-mile replacement program. Within EEP’s North Dakota system, the Bakken Expansion and Access programs, which enhance crude oil gathering capabilities in the Bakken region, were also a significant contributor to the adjusted earnings growth. Positive factors experienced by Canadian Mainline in 2014 as noted earlier also resulted in higher 2014 throughput on EEP’s Lakehead System. Partially offsetting the increase in adjusted earnings in EEP’s liquids business were incremental power costs associated with higher throughput, higher depreciation expense from an increased asset base and higher operating and administrative costs primarily associated with a larger workforce partially offset by lower pipeline integrity costs. Within EEP’s natural gas and NGL businesses, which it holds directly and indirectly through its partially-owned subsidiary, MEP, lower volumes mainly due to decreased drilling activity had a negative impact on adjusted earnings. Finally, EEP’s contribution to Enbridge’s adjusted earnings reflected higher earnings from Enbridge’s May 2013 investment in preferred units of EEP, higher incentive distributions and distributions from Class D units which were issued under the Equity Restructuring.

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 are 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 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). If after two years, the cumulative adjusted EBITDA of the Alberta Clipper Pipeline for fiscal years 2015 and 2016 is more than five percent below the EBITDA projections for those years, a number of Class E units representing US$50 million of value will be cancelled by EEP effective as of June 15, 2017 for no consideration.

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 initial capacity of the line was 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. 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 – Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Mainline Expansion.

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 perform necessary remediation, 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. On March 14, 2013, EEP received an order from the EPA (the EPA Order) which required additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. In February 2015, the EPA acknowledged EEP’s completion of the EPA Order. In November 2014, regulatory authority was transferred from the EPA to the Michigan Department of Environmental Quality (MDEQ). The MDEQ has oversight over the submerged oil reassessment, sheen management and sediment trap monitoring and maintenance activities through a Kalamazoo River Residual Oil Monitoring and Maintenance Work Plan.

In May 2015, EEP reached a settlement with the MDEQ 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, 2015, EEP’s total cost estimate for the Line 6B crude oil release was US$1.2 billion ($193 million after-tax attributable to Enbridge), which is unchanged since December 31, 2014. As at December 31, 2014, the total cost estimate for the Line 6B crude oil release increased by US$86 million as compared to December 31, 2013. The total cost increase of US$86 million during the year ended December 31, 2014, was primarily related to the MDEQ approved Schedule of Work, completion of the dredge activities near Ceresco and Morrow Lake and estimated civil penalties under the Clean Water Act of the United States (Clean Water Act), as described below under Legal and Regulatory Proceedings.

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, 2015. 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, in addition to fines and penalties and expenditures associated with litigation and settlement of claims.

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. On October 21, 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.

The total estimated cost for the Line 6A crude oil release was approximately US$51 million ($7 million after-tax attributable to Enbridge) before insurance recoveries and excluding fines and penalties. These costs included emergency response, environmental remediation and cleanup activities with the crude oil release. As at December 31, 2015, 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 which renews throughout the year. On May 1 of each year, the insurance program is renewed and includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents excluding costs for fines and penalties.

A majority of the costs incurred in connection with the crude oil release for Line 6B 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, 2015, 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 the existing insurance policy. As at December 31, 2015, 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 assert 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 now includes only one insurer.

Of the remaining US$103 million coverage limit, US$85 million is 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, which is not scheduled to occur until the fourth quarter of 2016. While EEP believes those costs are eligible for recovery, there can be no assurance that EEP will prevail in the arbitration.

Enbridge renewed its comprehensive property and liability insurance programs under which the Company is insured through April 30, 2016 with a liability program aggregate limit of US$860 million, which includes sudden and accidental pollution liability. In the unlikely event 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.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Five actions or claims are pending against Enbridge, EEP or their affiliates in United States federal and 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.

As at December 31, 2015, included in EEP’s estimated costs related to the Line 6B crude oil release is US$44 million in fines and penalties. Of this amount, US$40 million relates to civil penalties under the Clean Water Act. While no final fine or penalty has been assessed or agreed to date, EEP believes that, based on the best information available at this time, the US$40 million represents an estimate of the minimum amount which may be assessed, excluding costs of injunctive relief that may be agreed to with the relevant governmental agencies. Given the complexity of settlement negotiations, which EEP expects will continue, and the limited information available to assess the matter, EEP is unable to reasonably estimate the final penalty which might be incurred or to reasonably estimate a range of outcomes at this time. Injunctive relief is likely to include further measures directed toward enhancing spill prevention, leak detection and emergency response to environmental events. The cost of compliance with such measures, when combined with any fine or penalty, could be material. EEP has entered into a tolling agreement with the applicable governmental agencies and discussions with these governmental agencies regarding fines, penalties and injunctive relief are ongoing.

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 has 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.

Lakehead System Line 14 Crude Oil Release

On July 27, 2012, a release of crude oil was detected on Line 14 of EEP’s Lakehead System near Grand Marsh, Wisconsin. The estimated volume of oil released was approximately 1,700 barrels. EEP received a Corrective Action Order (CAO) from the PHMSA on July 30, 2012, followed by an amended CAO on August 1, 2012. Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. During the fourth quarter of 2013, EEP received approval from the PHMSA to remove the pressure restrictions and to return to normal operating pressures for a period of 12 months. In December 2014, the PHMSA again considered the status of the pipeline in light of information they acquired throughout 2014. On December 9, 2014, EEP received a letter from the PHMSA approving its request to continue the normal operation of Line 14 without pressure restrictions. EEP has no remaining estimated liability for this release.

EEP Preferred Unit Private Placement and Joint Funding Option Exercise

In May 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.

Concurrent with the issuance in May 2013, EEP also announced it expected to exercise its option in each of the Eastern Access and Lakehead System Mainline Expansion joint funding agreements to reduce its economic interest and associated funding in the respective projects. On June 28, 2013, EEP exercised each of the options and both projects are now being funded 75% by Enbridge and 25% by EEP. EEP will retain the option to increase its economic interest back up to 40% in each project within one year of the final project in-service dates.

Midcoast Energy Partners, L.P. – Initial Public Offering and Drop Down of Additional Interests

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. EEP’s direct interest in entities or partnerships holding the natural gas and NGL midstream operations is 48%, with the remaining ownership held by MEP. EEP retains a 2% GP interest, an approximate 52% limited partner interest and all IDR in MEP.

In May 2013, EEP formed MEP as its wholly-owned subsidiary. Subsequently, on November 13, 2013, MEP completed its initial public offering of 18.5 million Class A common units representing limited partner interests and subsequently issued an additional 2.8 million Class A common units pursuant to an underwriters’ over-allotment option. MEP received proceeds of approximately US$355 million. Upon finalization of the offering, MEP’s initial assets consisted of an approximate 39% ownership interest in EEP’s natural gas and NGL midstream business. EEP retained a 2% GP interest, an approximate 52% limited partner interest and all IDR in MEP, in addition to its 61% direct interest in the natural gas and NGL midstream assets.

On July 1, 2014, EEP completed the sale of an additional 12.6% limited partnership interest in its natural gas and NGL midstream business to MEP for cash proceeds of US$350 million. Upon finalization of this transaction, EEP continued to retain its interest in MEP as noted above; 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 these transactions resulted in a partial monetization of EEP’s natural gas and NGL midstream business through sale to noncontrolling interests (being MEP’s public unitholders). The proceeds from the drop down provided EEP a cost-effective funding alternative to execute its current liquids pipeline organic growth program.

Intercompany Accounts Receivable Sale

On June 28, 2013, certain of EEP’s subsidiaries entered into a Receivables Purchase Agreement (the Receivables Agreement) with a wholly-owned subsidiary of Enbridge, whereby Enbridge will purchase on a monthly basis certain trade and accrued receivables of such subsidiaries through December 2016. Pursuant to the Receivables Agreement, as amended on September 20, 2013, and again on December 2, 2013, at any one point the accumulated purchases, net of collections, shall not exceed US$450 million. 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.

Enbridge Energy Management, L.L.C. Share Issuance

Enbridge’s ownership in EEP is held through a combination of direct interest, including a 2% GP interest, and indirect interest through EEM. In 2013, EEM completed two separate issuances of Listed Shares. In March 2013, EEM completed the issuance of 10.4 million Listed Shares for net proceeds of approximately US$273 million and in September 2013, EEM completed a further issuance of 8.4 million Listed Shares for net proceeds of approximately US$236 million. Enbridge did not purchase any of the offered shares. EEM subsequently used the net proceeds from each of the offerings to invest in an equal number of i-units of EEP.

In connection with these issuances, the Company made capital contributions of US$6 million and US$5 million in March and September 2013, respectively, to maintain its 2% GP interest in EEP. The proceeds from the issuances were used by EEP to repay commercial paper, to finance a portion of its capital expansion program relating to its core liquids and natural gas systems and for general partnership purposes.

ENBRIDGE ENERGY, LIMITED PARTNERSHIP

EELP holds assets that are jointly funded by Enbridge and EEP. Included within EELP is the United States segment of Alberta Clipper Pipeline. The United States portion of the Alberta Clipper Pipeline connects with the Canadian portion of Alberta Clipper Pipeline at the border near Neche, North Dakota and provides transportation service to Superior, Wisconsin. Enbridge funded 66.7% of the project’s equity requirements through EELP, while 66.7% of the debt funding was made through EEP. On January 2, 2015, Enbridge transferred its 66.7% interest in the United States segment of Alberta Clipper to EEP. Refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Alberta Clipper Drop Down.

Also within EELP is Enbridge’s partnership interest in both the Eastern Access and Lakehead System Mainline Expansion projects. In 2012, EELP amended and restated its limited partnership agreement to establish a series of additional partnership interests in both the Eastern Access and Lakehead System Mainline Expansion projects. Both of these projects will be funded 75% by Enbridge and 25% by EEP. For further details on the respective projects, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access and Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Mainline Expansion.

Results of Operations

Earnings from EELP were $119 million for the year ended December 31, 2015 compared with $107 million for the year ended December 31, 2014. Adjusted earnings from EELP increased in 2015 due to contributions from assets recently placed into service, most notably the expansion of the Company’s mainline system completed in July 2015 and the expansion of Line 6B completed in phases during 2014 as part of the Company’s Eastern Access Program. Partially offsetting the increase in 2015 earnings was the absence of earnings from EELP’s interest in Alberta Clipper which was transferred to EEP on January 2, 2015.

Earnings from EELP were $107 million for the year ended December 31, 2014 compared with $38 million for the year ended December 31, 2013. Higher earnings reflected contributions from assets recently placed into service, most notably the expansion of Line 6B completed in phases during 2014 as part of the Company’s Eastern Access Program. Higher earnings from Eastern Access also reflected a higher surcharge rate due to the Lakehead System filing delay and other true-up adjustments. Also positively impacting earnings were higher tolls on Alberta Clipper.

BUSINESS RISKS

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

Asset Utilization

Asset utilization risk for EEP’s liquids business shares similar risk characteristics to Liquids Pipelines as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of EEP’s assets. The profitability of EEP’s liquids business depends to some extent on the throughput of products transported on its pipeline systems, and a decrease in volumes transported can directly and adversely affect revenues and earnings.

Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions, outside of EEP’s control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on EEP’s pipelines. However, the long-term outlook for Canadian crude oil production, particularly from western Canada, and increasing United States domestic production are expected to maintain a steady supply of crude oil.

EEP seeks to mitigate utilization constraints within its control. The market access and expansion projects under development are expected to reduce capacity bottlenecks and introduce new markets for customers. EEP 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 making continuous improvements to scheduling models and timelines to maximize throughput.

EEP’s natural gas gathering assets are also 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. EEP’s marketing business uses third party storage to balance supply and demand factors.

Operational and Economic Regulation

Regulatory scrutiny over the integrity of EEP’s assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on EEP’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 EEP.

EEP’s economic regulation is driven primarily through its ownership of interstate oil pipelines and certain activities within its intrastate natural gas pipelines, which are regulated by the FERC or 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 EEP’s revenues and earnings. Delays in regulatory approvals could result in cost escalations and construction delays, which also negatively impact EEP’s operations. Additionally, while EEP’s 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 EEP operates. In addition, the FERC has also taken an interest in regulating gas gathering systems that connect into interstate pipelines.

Competition

EEP’s Lakehead System, the United States portion of the liquids pipelines mainline, is a major crude oil export conduit from the WCSB. Other existing competing carriers and pipeline proposals to ship western Canadian liquids hydrocarbons to markets in the United States represent competition for the Lakehead System, including proposed projects expected to serve the Gulf Coast market. EEP’s Mid-Continent and North Dakota systems also face competition from existing competing pipelines, proposed future pipelines and existing and alternative gathering facilities, predominately rail. Competition for EEP’s storage facilities includes large integrated oil companies and other midstream energy partnerships.

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 EEP’s natural gas segment. 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 EEP.

EEP’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

EEP’s gas processing business is subject to commodity price risk arising from movements in natural gas and NGL prices and differentials. These risks have been managed 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, EEP’s earnings are exposed to associated changes in the mark-to-market value of these contracts.

CORPORATE

EARNINGS

	2015		2014		2013
(millions of Canadian dollars)
Noverco	50		43		54
Other Corporate	(33	)	(69	)	(82	)
Adjusted earnings/(loss)	17		(26	)	(28	)
Noverco - changes in unrealized derivative fair value gains/(loss)	(9	)	(5	)	4
Other Corporate - changes in unrealized derivative fair value loss	(520	)	(378	)	(306	)
Other Corporate - loss on de-designation of interest rate hedges in connection with the Canadian Restructuring Plan	(247	)	-		-
Other Corporate - transaction costs relating to the Canadian Restructuring Plan	(16	)	-		-
Other Corporate - deferred income tax out-of-period adjustments	71		-		-
Other Corporate - foreign tax recovery	-		-		4
Other Corporate - impact of tax rate changes	44		-		18
Other Corporate - drop down transaction costs	(6	)	(6	)	-
Other Corporate - asset impairment loss	(2	)	-		(6	)
Other Corporate - tax on intercompany gains on sale of partnership units	(39	)	(157	)	-
Other Corporate - gain on sale of investment	-		14		-
Other Corporate - employee severance costs	(19	)	-		-
Other Corporate - prior period adjustment	(6	)	-		-
Loss attributable to common shareholders	(732	)	(558	)	(314	)

Total adjusted earnings from Corporate were $17 million for the year ended December 31, 2015 compared with adjusted losses of $26 million for the year ended December 31, 2014 and adjusted losses of $28 million for the year ended December 31, 2013. Stronger operating earnings from Gaz Metro Limited Partnership (Gaz Metro) due to a favourable United States/Canada foreign exchange rate and incremental earnings from new assets drove higher Noverco adjusted earnings in 2015 compared with 2014. Noverco adjusted earnings in 2013 included favourable impacts of a small one-time gain on sale of an investment and equity earnings true-up adjustment.

Adjusted loss in Other Corporate decreased over the past two years, reflecting lower net Corporate segment finance costs, partially offset by higher preference share dividends reflecting additional preference shares issued in 2014 to fund the Company’s growth capital program.

Additional details on items impacting Corporate earnings/(loss) include:

· Other Corporate loss for each period included changes in the unrealized fair value losses on derivative financial instruments primarily related to forward foreign exchange risk management positions.

· Other Corporate loss for 2015 included an out-of-period adjustment to reduce deferred income tax expense related to intercompany preferred dividends.

· Other Corporate loss for 2015 included the impact of a corporate tax rate change in the province of Alberta on opening deferred income tax balances.

· Other Corporate loss for 2015 included employee severance costs in relation to the Company’s enterprise-wide reduction of workforce.

· Other Corporate loss for 2013 included a recovery of taxes related to a historical foreign investment.

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 Metro, 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. In 2014 and 2013, the board of directors of Noverco authorized the sale of a portion of its Enbridge common share holding to rebalance Noverco’s asset mix.

In 2014, Noverco sold 1.3 million Enbridge common shares through a secondary offering. Unlike the 2013 transaction discussed below, Enbridge did not receive a dividend from Noverco for its share of the net after-tax proceeds. On May 28, 2013, Noverco sold 15 million Enbridge common shares through a secondary offering. Enbridge’s share of the net after-tax proceeds of approximately $248 million was received as dividends from Noverco on June 4, 2013 and was used to pay a portion of the Company’s quarterly dividend on September 1, 2013. A portion of this dividend did not qualify for the enhanced dividend tax credit in Canada and, accordingly, was not designated as an “eligible dividend”. The dividend was a “qualified dividend” for United States tax purposes.

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 4.3% to 4.4%.

Results of Operations

Noverco adjusted earnings were $50 million for the year ended December 31, 2015 compared with $43 million for the year ended December 31, 2014. Noverco adjusted earnings included returns on the Company’s preferred share investments, as well as its equity earnings from Noverco’s underlying gas and power distribution investments through Gaz Metro. The increase in year-over-year adjusted earnings reflected stronger operating earnings from Gaz Metro due to a favourable United States/Canada foreign exchange rate on Gaz Metro’s United States based business and incremental earnings from new assets. Partially offsetting the higher adjusted earnings were lower preferred share dividend income based on lower yield of 10-year Government of Canada bonds.

Noverco adjusted earnings decreased to $43 million for the year ended December 31, 2014 from $54 million for the year ended December 31, 2013. Excluding the impact of a small one-time gain on sale of an investment in the first quarter of 2013 and an equity earnings true-up adjustment also recognized in the first quarter of 2013, Noverco adjusted earnings were slightly higher for the year ended December 31, 2014 and reflected stronger operating earnings from Gaz Metro and higher preferred share dividend income.

OTHER CORPORATE

Corporate also consists of the new business development activities, general corporate investments and financing costs not allocated to the business segments. Other corporate costs include dividends on preference shares as such dividends are a deduction in determining earnings attributable to common shareholders.

Results of Operations

Other Corporate adjusted loss was $33 million for the year ended December 31, 2015 compared with an adjusted loss of $69 million for the year ended December 31, 2014. The decrease in adjusted loss reflected lower net Corporate segment finance costs in the first half of 2015 and lower income taxes partially offset by higher preference share dividends from an increase in the number of preference shares outstanding and higher operating and administrative costs.

Other Corporate adjusted loss was $69 million for the year ended December 31, 2014 compared with an adjusted loss of $82 million for the year ended December 31, 2013. The decrease in adjusted loss reflected lower net Corporate segment finance costs and lower income taxes partially offset by higher preference share dividends from an increase in the number of preference shares outstanding and higher operating and administrative costs.

Preference Share Issuances

Since July 2011, the Company has issued 260 million preference shares for gross proceeds of approximately $6,527 million with the following characteristics. See Outstanding Share Data.

Gross Proceeds

Initial
Yield

Dividend

Per Share
Base
Redemption
Value

Redemption
and Conversion
Option Date

2,3

Right to
Convert
Into

3,4

(Canadian dollars, unless otherwise stated)

Series B5

$500 million

4.0%

$1.00

$25

June 1, 2017

Series C

Series D5

$450 million

4.0%

$1.00

$25

March 1, 2018

Series E

Series F5

$500 million

4.0%

$1.00

$25

June 1, 2018

Series G

Series H5

$350 million

4.0%

$1.00

$25

September 1, 2018

Series I

Series J5

US$200 million

4.0%

US$1.00

US$25

June 1, 2017

Series K

Series L5

US$400 million

4.0%

US$1.00

US$25

September 1, 2017

Series M

Series N5

$450 million

4.0%

$1.00

$25

December 1, 2018

Series O

Series P5

$400 million

4.0%

$1.00

$25

March 1, 2019

Series Q

Series R5

$400 million

4.0%

$1.00

$25

June 1, 2019

Series S

Series 15

US$400 million

4.0%

US$1.00

US$25

June 1, 2018

Series 2

Series 35

$600 million

4.0%

$1.00

$25

September 1, 2019

Series 4

Series 55

US$200 million

4.4%

US$1.10

US$25

March 1, 2019

Series 6

Series 75

$250 million

4.4%

$1.10

$25

March 1, 2019

Series 8

Series 95

$275 million

4.4%

$1.10

$25

December 1, 2019

Series 10

Series 115

$500 million

4.4%

$1.10

$25

March 1, 2020

Series 12

Series 135

$350 million

4.4%

$1.10

$25

June 1, 2020

Series 14

Series 155

$275 million

4.4%

$1.10

$25

September 1, 2020

Series 16

1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend per year, as declared by the Board of Directors of the Company.

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 Holders will be entitled 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) or 2.7% (Series 16)); 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 – Financing Activities.

Common Share Issuance

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 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.

On April 16, 2013, the Company completed the issuance of 13 million Common Shares for gross proceeds of approximately $600 million.

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 the issuance of debt, 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. Furthermore, the Company targets to maintain sufficient standby liquidity to bridge fund through protracted capital markets disruptions. The Company targets to maintain sufficient liquidity through committed credit facilities with a diversified group of banks and 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 through which it can monetize assets, with the objective of diversifying funding sources and maintaining access to low cost capital.

Enbridge continued to utilize its sponsored vehicles to enhance its enterprise-wide funding program. In November 2014, Enbridge finalized an agreement to transfer natural gas and diluent pipeline interests to the Fund, a transaction that provided Enbridge with approximately $1.2 billion of net funding for its growth capital program. Refer to Sponsored Investments – The Fund Group – The Fund Group Drop Down Transaction. In September 2015, with the completion of the Canadian Restructuring Plan, the Company achieved a significant milestone relating to its sponsored vehicles dropdown strategy in Canada. For further details, refer to Canadian Restructuring Plan.

Following the Company’s announcement of the execution of the definitive agreement in connection with the Canadian Restructuring Plan, and ENF receiving shareholder approval thereof, as applicable, certain credit ratings of the Company were revised or affirmed as follows:

· DBRS Limited downgraded the Company’s issuer rating and medium-term notes and unsecured debentures rating from A (low) to BBB (high), downgraded the Company’s commercial paper rating from R-1 (low) to R-2 (high) and downgraded the Company’s preference share rating from Pfd-2 (low) to Pfd-3 (high), all with stable trends.

· Moody’s Investor Services, Inc. (Moody’s) downgraded the Company’s issuer rating and medium-term notes and unsecured debt rating from Baa1 to Baa2 and updated this rating outlook to stable and downgraded the Company’s preference share credit rating from Baa3 to Ba1 and updated this rating outlook to stable. Moody’s also affirmed the Company’s United States commercial paper rating of P-2.

· Standard & Poor’s Ratings Services (S&P) downgraded the Company’s corporate credit rating and unsecured debt rating from A- to BBB+ and removed these ratings from credit watch and downgraded the Company’s preference share credit rating from P-2 to P-2 (low) and removed this rating from credit watch. S&P also affirmed the Company’s Canadian commercial paper credit rating of A-1 (low), removed this rating from credit watch and maintained a global overall A-2 short-term rating and removed this rating from credit watch.

The Company’s investment grade credit ratings are 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. All ratings now have a stable outlook and the Company believes that it continues to have appropriate access to financial markets both in Canada and the United States.

In the United States, under the sponsored vehicles program, the restructuring of EEP’s equity that was completed in 2014 is expected to benefit Enbridge in the longer term by lowering EEP’s cost of capital and improving its growth outlook, thus increasing incentive distributions to Enbridge and enhancing its ability to undertake drop down transactions and third party acquisitions. For further details of the Equity Restructuring, refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Equity Restructuring. 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 Sponsored Investments – Enbridge Energy Partners, L.P. – Alberta Clipper Drop Down. Enbridge will continue to evaluate opportunities to generate value for its shareholders through selective dropdowns of its United States liquids pipelines assets of approximately $500 million annually to EEP depending on market conditions.

In accordance with its funding plan, the Company completed the following public issuances in 2015:

Segment	Entity	Type of Issuance	Amount
(millions of Canadian dollars, unless stated otherwise)
Gas Distribution	EGD	Medium-term notes	570
Sponsored Investments	EPI (via the Fund Group)	Medium-term notes	1,000
Sponsored Investments	EEP	Class A common units	US$294
Sponsored Investments	EEP	Senior notes	US$1,600
Sponsored Investments	ENF	Common shares	700

To ensure ongoing liquidity and to 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, 2015 and 2014.

		2015			2014
December 31,	Maturity	Total Facilities	Draws1	Available	Total Facilities
(millions of Canadian dollars)
Liquids Pipelines2	2017	28	-	28	300
Gas Distribution	2017-2019	1,010	603	407	1,008
Sponsored Investments2	2017-2020	9,224	4,089	5,135	4,531
Corporate	2017-2020	11,458	7,357	4,101	12,772
Total committed credit facilities3		21,720	12,049	9,671	18,611

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

2 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group within the Sponsored Investments segment as described under the Canadian Restructuring Plan. Liquids Pipelines total facilities of $300 million as at December 31, 2014 have not been reclassified into the Sponsored Investments segment for presentation purposes.

3 On August 18, 2014, long-term private debt was issued for $352 million and US$1,061 million related to Southern Lights project financing. The proceeds were utilized to repay the construction credit facilities on a dollar-for-dollar basis.

In addition to the committed credit facilities noted above, the Company also has $349 million (2014 - $361 million) of uncommitted demand credit facilities, of which $185 million (2014 - $80 million) was unutilized as at December 31, 2015.

The Company’s net available liquidity of $10,325 million at December 31, 2015 was inclusive of $1,015 million of unrestricted cash and cash equivalents and net of bank indebtedness of $361 million as reported on the Consolidated Statements of Financial Position.

The Company’s credit facility agreements 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, 2015, 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, 2015, the Company’s debt capitalization ratio was 65.5% compared with 63.1% as at December 31, 2014.

The Company invests a portion of its surplus cash in short-term investment grade instruments with creditworthy counterparties. Short-term investments were $27 million as at December 31, 2015 compared with $308 million as at December 31, 2014. Surplus cash at December 31, 2015 provides additional liquidity and can be used to fund the Company’s growth projects.

There are no material restrictions on the Company’s cash with the exception of cash in trust of $34 million related to 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, 2015 and 2014 the Company had a negative working capital position of $1,227 million and $296 million, respectively, which contemplates the realization of assets and the liquidation of liabilities. In both periods, the major contributing factor is the funding of the Company’s growth capital program.

Despite this negative working capital, the Company has significant net available liquidity through committed credit facilities and other sources as previously discussed, which allow the funding of liabilities as they become due. As at December 31, 2015, the net available liquidity totalled $10,325 million (2014 - $9,291 million). It is anticipated that any current maturities of long-term debt will be refinanced upon maturity.

December 31,	2015		2014
(millions of Canadian dollars)
Cash and cash equivalents1	1,049		1,308
Accounts receivable and other2	5,437		5,745
Inventory	1,111		1,148
Bank indebtedness	(361	)	(507	)
Short-term borrowings	(599	)	(1,041	)
Accounts payable and other3	(7,399	)	(6,524	)
Interest payable	(324	)	(264	)
Environmental liabilities	(141	)	(161	)
Working capital	(1,227	)	(296	)

1 Includes Restricted cash.

2 Includes Accounts receivable from affiliates.

3 Includes Accounts payable to affiliates.

OPERATING ACTIVITIES

Cash generated from operating activities was $4,571 million for the year ended December 31, 2015 (2014 - $2,547 million; 2013 - $3,341 million). Excluding the timing effect of changes in operating assets and liabilities, the Company has delivered a growing cash flow stream over the last two years.

The Company’s cash flows from operating activities in 2015 have increased by $2,024 million and $1,230 million, relative to 2014 and 2013 respectively. The cash growth delivered by operations is a reflection of the positive factors discussed in Performance Overview, which include higher throughput on the Canadian Mainline, higher volumes and tolls on EEP’s liquids business, contributions from new liquids pipeline assets placed into service in recent years and strong refinery demand for crude oil feedstock leading to more favourable tank management opportunities for Energy Services. Partially offsetting these positive factors were higher financing costs over the last two years, associated with funding of the Company’s growth program.

Enbridge’s operating assets and liabilities fluctuate in the normal course due to various factors including fluctuations in commodity prices and activity levels within Energy Services and Gas Distribution, the timing of tax payments, general variations in activity levels within the Company’s businesses, as well as timing of cash receipts and payments.

In 2015, the year-over-year change in cash generated from operating activities was impacted by a favourable variance of $1,035 million for changes in operating assets and liabilities, 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. The year-over year variance was also positively impacted by the normal course factors noted above. Partially offsetting the favourable variance was higher inventory in Energy Services, as a result of increased activity from the completion of the Seaway Pipeline Twin and Flanagan South projects in late 2014.

In 2014, the year-over-year change in cash from operating activities was impacted by an unfavourable variance of $1,312 million from changes in operating assets and liabilities, mainly attributable to fluctuations in crude oil prices in the marketing and liquids businesses during the fourth quarter resulting in lower accounts payable balances, as well as increases in regulatory receivables from the gas distribution business.

INVESTING ACTIVITIES

Cash used in investing activities was $7,933 million for the year ended December 31, 2015 (2014 - $11,891, 2013 - $9,431) and reflected the Company’s continued successful execution of its growth capital program that it has undertaken over recent years as described under Growth Projects – Commercially Secured Projects.

A summary of additions to property, plant and equipment for the years ended December 31, 2015, 2014 and 2013 is set out below:

Year ended December 31,	2015	2014	2013
(millions of Canadian dollars)
Liquids Pipelines	2,955	5,914	4,359
Gas Distribution	858	603	533
Gas Pipelines, Processing and Energy Services	226	678	744
Sponsored Investments	3,158	3,269	2,565
Corporate	76	60	34
Total capital expenditures	7,273	10,524	8,235

The timing of growth projects’ approval, construction and in-service dates impact the timing of cash requirements. Cash used in investing activities was higher in 2014 as the Company successfully completed its significant growth projects such as Flanagan South and also made significant progress on major components of the Eastern Access Program and Edmonton to Hardisty Expansion project, which were completed in 2015. In 2015 the Company continued its growth program which included significant spending on the GTA and Southern Access Extension projects.

Other notable investing activities over the last three years included the acquisition of the Company’s 24.9% interest in the 400-MW Rampion Project in the United Kingdom in 2015, acquisition of Magic Valley and Wildcat wind farms in 2014, and funding of investments in Seaway Pipeline Twin in 2014 and 2013 and Texas Express NGL System in 2013.

FINANCING ACTIVITIES

Cash generated from financing activities was $2,973 million for the year ended December 31, 2015 (2014 - $9,770 million, 2013 - $5,070 million). The year-over-year reduction of cash generated from financing activities in 2015 reflected lower capital requirements as a result of a combination of timing of capital expenditures, as noted above, and increased cash flow generation from operations.

In 2015, the Company increased its overall debt by $3,663 million (2014 - $9,000 million; 2013 - $3,392 million). The increase resulted from the issuance of medium-term and senior notes, net of repayments, of $2,744 million (2014 - $5,573 million; 2013 - $2,185 million) and increased credit facility and commercial paper draws, net of repayments, of $1,507 million (2014 - $2,693 million; 2013 - $1,557 million), partially offset by a reduction of $588 million in bank indebtedness and short-term borrowings (2014 - increased by $734 million; 2013 - decreased by $350 million).

Financing activities also include transactions between the Company’s Sponsored Investments and their public unitholders, also referred to as 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. In 2014 the Company made distributions, net of contributions, of $79 million to its noncontrolling interests; whereas in 2013, the Company received contributions, net of distributions of $474 million, primarily as a result of sponsored vehicles’ equity issuances to the public.

During the years ended December 31, 2014 and 2013, the Company actively issued preference shares and common shares to the public and raised net proceeds of $1,365 million and $1,428 million, respectively, from the issuance of preference shares, and $478 million and $628 million, respectively, from the issuance of common shares. With higher preference shares and common shares outstanding along with an increase in the common share dividend rate, the amount of dividends paid by the Company has increased over the last two years.

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, 2015, dividends declared were $1,596 million (2014 - $1,177 million), of which $950 million (2014 - $749 million) were paid in cash and reflected in financing activities. The remaining $646 million (2014 - $428 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, 2015 and 2014, 40.5% and 36.4%, respectively, of total dividends declared were reinvested.

On December 2, 2015, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2016 to shareholders of record on February 16, 2016.


Common Shares		$0.53000
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

CONTRACTUAL OBLIGATIONS

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

	Total	Less than 1 year	1-3 years	3-5 years	After 5 years
(millions of Canadian dollars)
Long-term debt1	30,224	1,987	3,836	4,724	19,677
Capital and operating leases	1,102	123	189	133	657
Long-term contracts	14,445	5,505	3,200	2,187	3,553
Pension obligations2	118	118	-	-	-
Total contractual obligations	45,889	7,733	7,225	7,044	23,887

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 Assumes only required payments will be made into the pension plans in 2016. Contributions are made in accordance with independent actuarial valuations as at December 31, 2015. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.

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 $3,993 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.

OUTSTANDING SHARE DATA1

PREFERENCE SHARES

	Number	Redemption and Conversion Option Date2,3	Right to Convert 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

COMMON SHARES

	Number
Common Shares - issued and outstanding (voting equity shares)	867,797,356
Stock Options - issued and outstanding (20,413,827 vested)	35,794,798

1 Outstanding share data information is provided as at February 17, 2016.

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.

QUARTERLY FINANCIAL INFORMATION

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 weather	(33	)	6		-		16	(11	)
Changes in unrealized derivative fair value (gains)/loss	977		(296	)	654		45	1,380

2014	Q1		Q2		Q3		Q4		Total
(millions of Canadian dollars, except for per share amounts)
Revenues	10,521		10,026		8,297		8,797		37,641
Earnings/(loss) attributable to common shareholders	390		756		(80	)	88		1,154
Earnings/(loss) per common share	0.48		0.92		(0.10	)	0.11		1.39
Diluted earnings/(loss) per common share	0.47		0.91		(0.10	)	0.10		1.37
Dividends paid per common share	0.3500		0.3500		0.3500		0.3500		1.40
EGD - warmer/(colder) than normal weather	(33	)	(4	)	2		(1	)	(36	)
Changes in unrealized derivative fair value (gains)/loss	190		(430	)	396		164		320

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 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 across business segments.

· 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 Canadian Restructuring Plan, 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.

· Included in the second quarter of 2015 and fourth quarter of 2014 were the tax impact 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 have remained in consolidated earnings and resulted in a charge of $39 million and $157 million, respectively.

· Included in earnings are after-tax gains on the disposal of non-core Offshore assets. The Company recognized gains of $4 million in the second quarter of 2015 and $43 million and $14 million in first and fourth quarters of 2014, respectively. Earnings in the first quarter of 2014 also included a $14 million after-tax gain on the sale of an Alternative and Emerging Technologies investment within the Corporate segment.

· Included in earnings is the Company’s share of after-tax leak remediation costs associated with the Line 6B crude oil release. Remediation costs of $5 million and $12 million were recognized in the second and third quarters of 2014. In the fourth quarter of 2014, the Company recognized an out-of-period adjustment of $5 million to reduce Enbridge’s share of leak remediation costs recognized in the third quarter of 2014.

· Included in earnings are after-tax costs of $6 million in the second quarter of 2015 and $4 million in the third quarter of 2014, in connection with the Line 37 crude oil release which occurred in June 2013. Earnings also reflected insurance recoveries associated with the Line 37 crude oil release of $9 million recognized in the first quarter of 2015 and $4 million recognized in each of the second quarter and fourth quarter of 2014, respectively. In the fourth quarter of 2015, earnings reflected the Company’s share of after-tax insurance recoveries of $13 million under the Fund Group within Sponsored Investments.

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 and Other Announced Projects Under Development.

RELATED PARTY TRANSACTIONS

Other than the drop down transactions between Enbridge and its sponsored vehicles, including the Canadian Restructuring Plan, 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.

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, 2015 (2014 - $7 million; 2013 - $6 million).

Certain wholly-owned subsidiaries within the Company’s Gas Distribution, Gas Pipelines, Processing and Energy Services and Sponsored Investments 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, 2015 were $332 million (2014 - $256 million; 2013 - $222 million).

Certain wholly-owned subsidiaries within Gas Distribution and Gas Pipelines, Processing and Energy Services made natural gas and NGL purchases of $228 million (2014 - $315 million; 2013 - $99 million) from several joint venture affiliates during the year ended December 31, 2015.

Natural gas sales of $5 million (2014 - $58 million; 2013 - $10 million) were made by certain wholly-owned subsidiaries within Gas Pipelines, Processing and Energy Services to several joint venture affiliates during the year ended December 31, 2015.

LONG-TERM NOTES RECEIVABLE FROM AFFILIATES

Amounts receivable from affiliates include a series of loans to Vector and other affiliates totalling $149 million and $3 million, respectively (2014 - $183 million and nil, 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.

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.

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 through 2019 via execution of floating to fixed interest rate swaps with an average swap rate of 2.0%.

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 through 2019 via execution of floating to fixed interest rate swaps with an average swap rate of 3.4%.

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

The following table presents the effect of derivative instruments on the Company’s consolidated earnings and consolidated comprehensive income.

Year ended December 31,	2015		2014		2013
(millions of Canadian dollars)
Amount of unrealized gains/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	77		8		56
Interest rate contracts	(275	)	(1,086	)	814
Commodity contracts	9		50		(9	)
Other contracts	(47	)	13		(2	)
Net investment hedges
Foreign exchange contracts	(248	)	(113	)	(81	)
	(484	)	(1,128	)	778
Amount of gains/(loss) reclassified from Accumulated other comprehensive income (AOCI) to earnings (effective portion)
Foreign exchange contracts1	9		8		(8	)
Interest rate contracts2	128		101		107
Commodity contracts3	(46	)	4		1
Other contracts4	28		(7	)	-
	119		106		100
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	21		216		51
Commodity contracts3	5		(6	)	(3	)
	26		210		48
Amount of gains/(loss) from non-qualifying derivatives included in earnings
Foreign exchange contracts1	(2,187	)	(936	)	(738	)
Interest rate contracts2,5	(363	)	4		(10	)
Commodity contracts3	199		1,031		(496	)
Other contracts4	(22	)	7		(3	)
	(2,373	)	106		(1,247	)

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

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

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

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

5 The amounts above include $338 million for the year ended December 31, 2015 relating to the de-designation of qualifying hedges in connection with the Canadian Restructuring Plan.

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. 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 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. However, leading up to the closure of the Canadian Restructuring Plan, the Company did not access the public markets as regularly as it had in previous years. However, once the Canadian Restructuring Plan was closed, Enbridge again began to access the public debt and equity markets in normal course. The Company is in compliance with all the terms and conditions of its committed credit facilities as at December 31, 2015. 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.

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 by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements.

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

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 Northern Gateway. 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.

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 Change Policy and Aboriginal and Native American Policy).

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 Aboriginal 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.

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. Major Projects 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 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 Major Projects to engage in open dialogue with government agencies, regulators, land owners, Aboriginal groups and special interest groups to identify and develop appropriate responses to their concerns regarding the Company’s projects.

Operational and Economic Regulation, Permits and Approvals

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

Operational regulation risks relate to failing to comply with applicable operational rules and regulations from government organizations and could result in fines, operating restrictions or shutdown of assets or an overall increase in operating and compliance costs. Regulatory scrutiny over the Company’s 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.

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. 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 could result in cost escalations, construction delays and in-service 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 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.

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 may involve significant price and integration risk.

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 with consistent due diligence processes, including a thorough review of the asset quality, systems and financial performance of the assets being assessed.

Operational Risks

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 efforts to reduce 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 and 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. The total insurance coverage will be allocated on an equitable basis in the unlikely event multiple insurable incidents exceeding the Company’s coverage limits are experienced by Enbridge and two Enbridge subsidiaries covered by the same policy within the same insurance period.

Public, Worker and Contractor Safety

Several of the Company’s pipeline systems run adjacent 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 above 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.

Information Technology Security or Systems Incident

The Company’s infrastructure, applications and data are becoming 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 and threat detection and incident response through a security operations centre. The Company’s information technology security operations are consolidated under one leadership structure to increase consistency and compliance with the Company’s security requirements across business segments.

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 is expected to be completed by the end of the first quarter of 2016, will be a key mitigation as the project is expected to provide significant diversification of gas supply to EGD’s distribution network and will further reduce the likelihood of a service interruption incident.

Business Environment Risks

Aboriginal Relations

Canadian judicial decisions have recognized that Aboriginal 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 Aboriginal people when its decisions or actions may adversely affect Aboriginal 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 Aboriginal rights may mean regulatory approval is denied or the conditions in the approval make a project economically challenging.

Given this environment and the breadth of relationships across the Company’s geographic span, Enbridge has implemented an Aboriginal and Native American Policy. This policy promotes the achievement of participative and mutually beneficial relationships with Aboriginal and Native American groups affected by the Company’s projects and operations. Specifically, the policy sets out principles governing the Company’s relationships with Aboriginal and Native American people and makes commitments to work with Aboriginal people and Native Americans 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 Aboriginal and Native American 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.

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, 2015 of $64,434 million (2014 - $53,830 million), or 76.1% of total assets, is generally provided on a straight-line basis over the estimated service lives of the assets commencing when the asset is placed in service. 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.

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.

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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 AER 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, 2015, the Company’s significant regulatory assets totalled $1,782 million (2014 - $2,174 million) and significant regulatory liabilities totalled $869 million (2014 - $962 million).

POSTRETIREMENT BENEFITS

The Company maintains pension plans, which provide defined benefit and/or defined contribution pension benefits and OPEB to eligible retirees. Pension costs and obligations for the defined benefit pension plans are determined using the universal method. This method involves complex actuarial calculations using several assumptions including discount rates, which were determined by referring to 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, expected rates of return on plan assets, health-care cost trend rates, projected salary increases, retirement age, mortality and termination rates. These assumptions are determined by management and 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 shortfall from the expected return on plan assets was $62 million for the year ended December 31, 2015 (2014 - $58 million excess) as disclosed in Note 26, Retirement and Postretirement Benefits, to the 2015 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.

The following sensitivity analysis identifies the impact on the December 31, 2015 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	209		31		24	1
Decrease in expected return on assets	-		10		-	1
Decrease in rate of salary increase	(43	)	(14	)	-	-

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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 2015 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 ACCOUNTING POLICY

Principles of Consolidation and Noncontrolling Interests

As a result of the Canadian Restructuring Plan, ECT, a subsidiary of the Company, determines its equity investment earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the HLBV method to its equity method investments where cash distributions, including both preference and residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that ECT would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s share of the earnings or losses from the equity investment for the period.

While ECT and EIPLP are both consolidated in the financial statements of Enbridge, the use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of Earnings. The Company continues to recognize Redeemable noncontrolling interests on its Consolidated Statements of Financial Position at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares.

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ADOPTION OF NEW STANDARDS

Extraordinary and Unusual Items

Effective January 1, 2015, the Company retrospectively adopted ASU 2015-01 which eliminates the concept of extraordinary items from U.S. GAAP. Entities will no longer be required to separately classify and present extraordinary items in the Consolidated Statements of Earnings. There was no material impact to the Company’s consolidated financial statements as a result of adopting this update.

Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity

Effective January 1, 2015, the Company prospectively adopted Accounting Standards Update (ASU) 2014-08 which changes the criteria and disclosures for reporting discontinued operations. The revised criteria will in general, result in fewer transactions being categorized as discontinued operations. There was no material impact to the consolidated financial statements as a result of adopting this update.

FUTURE ACCOUNTING POLICY CHANGES

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 Statement 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.

Classification of Deferred Taxes on the Statement of Financial Position

ASU 2015-17 was issued in November 2015 with the intent to simplify the presentation of deferred income taxes. The amendments require that deferred tax liabilities and assets be classified as noncurrent in a Statement of Financial Position. The accounting update is effective for fiscal years beginning after December 15, 2016 and is to be applied on a prospective or retrospective basis. The Company is currently assessing the impact of the new standard on its consolidated financial statements. Early application is permitted for all entities as of the beginning of an interim or annual reporting period. Effective January 1, 2016, the Company will elect to early adopt ASU 2015-17.

Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations

ASU 2015-16 was issued in September 2015 with the intent to simplify the accounting for measurement-period adjustments in business combinations. 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 accounting update is effective for fiscal years beginning after December 15, 2015 and is to be applied on a prospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements.

Simplifying the Measurement of Inventory

ASU 2015-11 was issued in July 2015 with the intent to simplify the measurement of inventory. The new standard requires inventory to be measured at the lower of cost and net realizable value and is applicable to all inventory, with the exception of inventory measured using last-in, first-out or the retail inventory method. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The new standard is effective for annual and interim reporting periods beginning after December 15, 2016 and is to be applied on a prospective basis.

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Measurement Date of Defined Benefit Obligation and Plan Assets

ASU 2015-04 was issued in April 2015 with the intent to simplify the fair value measurement of defined benefit plan assets and obligations. For entities with a fiscal year end that does not coincide with a month end, the new standard permits an entity to measure its defined benefit plan assets and obligations using the month end that is closest to the entity’s fiscal year end. In addition, where there are significant events in an interim period that would trigger a re-measurement of the plan assets and obligations, an entity is also permitted to re-measure such assets and obligations using the month end that is closest to the date of the significant event. The accounting update is effective for financial statements issued for fiscal years beginning after December 15, 2015 and is to be applied on a prospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements.

Simplifying the Presentation of Debt Issuance Costs

ASU 2015-03 was issued in April 2015 with the intent to simplify the presentation of debt issuance costs. The new standard requires a debt issuance cost related to a recognized debt liability to be presented in the Consolidated Statement 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. Further, ASU 2015-15 was issued in August 2015 to clarify 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. The accounting updates are effective for financial statements issued for fiscal years beginning after December 15, 2015 on a retrospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements.

Amendments to the Consolidation Analysis

ASU 2015-02, issued in February 2015, revises the current consolidation guidance which results in a change in the determination of whether an entity consolidates certain types of legal entities. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The new standard is effective for annual and interim reporting periods beginning after December 15, 2015 and may be applied on a full or modified retrospective basis.

Hybrid Financial Instruments Issued in the Form of a Share

ASU 2014-16 was issued in November 2014 with the intent to 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 Company does not expect the adoption of ASU 2014-16 to have a material impact on its consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2015 and is to be applied on a modified retrospective basis.

Development Stage Entities

ASU 2014-10, issued in June 2014, amended the consolidation guidance to eliminate the development stage entity relief when applying the variable interest entity model and evaluating the sufficiency of equity at risk. The Company is currently evaluating the impact of the amendment to the consolidation guidance, which is effective for annual reporting periods beginning after December 15, 2015. The new standard requires these amendments be applied retrospectively.

Revenue from Contracts with Customers

ASU 2014-09 was issued in May 2014 with the intent of significantly enhancing comparability of revenue recognition practices across entities and industries. The new standard provides a single principles-based, five-step model to be applied to all contracts with customers and introduces new, increased disclosure requirements. The Company is currently assessing the impact of the new standard on its consolidated financial statements. In July 2015, the effective date of the new standard was delayed by one year and the new standard is now effective for annual and interim periods beginning on or after December 15, 2017 and may be applied on either a full or modified retrospective basis.

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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, 2015, 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 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.

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, 2015, 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, 2015.

During the year ended December 31, 2015, 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, 2015 has been audited by PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company.

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