MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (MD&A) dated February 19, 2015 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, 2014, prepared in accordance with accounting principles generally accepted 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 and an increasing involvement in power transmission. 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 more than 2,200 megawatts (MW) (1,600 MW net) of renewable and alternative energy generating capacity and is expanding its interests in wind, solar and geothermal facilities. Enbridge employs more than 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

Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines and terminals in Canada and the United States, including Canadian Mainline, 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.

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.

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 fractionation and extraction 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 33.7% 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). Also within Sponsored Investments is the Company’s overall 66.4% economic interest in Enbridge Income Fund (the Fund), held both directly and indirectly through Enbridge Income Fund Holdings Inc. (ENF). 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.

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. The primary operations of the Fund include renewable power generation, natural gas transmission (through its 50% interest in Alliance Pipeline) and crude oil and liquids pipeline transportation, which includes feeder pipelines and storage facilities in western Canada and an interest in the Southern Lights Pipeline.

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

In December 2014, Enbridge announced its plan to transfer the majority of its Canadian Liquids Pipelines business comprising Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines (Athabasca) Inc. (EP Athabasca), and certain Canadian renewable energy assets with a combined carrying value of approximately $17 billion, with an associated secured growth capital program of approximately $15 billion, to the Fund (collectively, the Canadian Restructuring Plan). The transfer of the assets is expected to be completed in mid-2015. The Canadian Restructuring Plan was announced along with a 33% increase to the Company’s next quarterly common share dividend effective on March 1, 2015 along with a corresponding new dividend payout policy range. For further details on the dividend increase and change in dividend payout policy range, refer to Performance Overview – Dividends.

The Canadian Restructuring Plan is intended to enhance Enbridge’s value to investors while the Company executes its $44 billion growth capital program and to enhance the competitiveness of its funding costs for new organic growth opportunities and asset acquisitions. Transferring the assets to the Fund is expected to allow the majority of the growth capital program to be funded at an advantageous cost, while reducing the funding requirement at Enbridge. It also allows Enbridge to monetize a portion of its existing assets on favourable terms, releasing capital from the business for redeployment into future growth opportunities.

Pursuant to the plan, ENF is expected to acquire an increasing interest in the assets through investments in the equity of the Fund over a period of several years in amounts consistent with its equity funding capability. The Canadian Restructuring Plan has been approved in principle by Enbridge’s Board of Directors, but it remains subject to finalization of preliminary internal reorganization steps and a number of internal and external consents and approvals, including final approval of definitive transfer terms by the Enbridge Board of Directors and by the boards of ENF and the Fund, following a recommendation by an independent committee of ENF and the Fund and the receipt of all necessary shareholder and regulatory approvals that may be required. Assuming all necessary consents and approvals are obtained, the transfer and initial investment by ENF are targeted for completion mid-2015. However, there can be no assurance that the planned restructuring will be completed in the manner contemplated, or at all, or that the current market conditions and the Company’s future forecast, based on such market conditions, will not materially change.

Enbridge’s Canadian Liquids Pipelines includes its Canadian Mainline system held through EPI and its Regional Oil Sands System held through EP Athabasca. Both entities would be transferred from direct ownership by Enbridge to ownership by the Fund. Enbridge will retain operating responsibility for the Liquids Pipelines business, as it does for the assets currently held through the Fund and for those held through EEP, as well as responsibility for business development and project construction. In particular, Enbridge’s enterprise-wide priority on the safety and reliability of its operations, including protection of employees, the public and the environment, will continue to apply to Canadian Liquids Pipelines.

PERFORMANCE OVERVIEW

	Three months ended		Year ended
	December 31,		December 31,
	2014	2013	2014	2013	2012
(millions of Canadian dollars, except per share amounts)
Earnings attributable to common shareholders
Liquids Pipelines	19	46	463	427	697
Gas Distribution	69	80	213	129	207
Gas Pipelines, Processing and Energy Services	185	(325)	571	(68)	(377)
Sponsored Investments	140	79	419	268	283
Corporate	(325)	(151)	(558)	(314)	(129)
Earnings/(loss) attributable to common shareholders from continuing operations	88	(271)	1,108	442	681
Discontinued operations - Gas Pipelines, Processing and Energy Services	-	4	46	4	(79)
	88	(267)	1,154	446	602
Earnings/(loss) per common share	0.11	(0.33)	1.39	0.55	0.78
Diluted earnings/(loss) per common share	0.10	(0.33)	1.37	0.55	0.77
Adjusted earnings1
Liquids Pipelines	199	205	858	770	655
Gas Distribution	68	67	177	176	176
Gas Pipelines, Processing and Energy Services	30	17	136	203	176
Sponsored Investments	123	89	429	313	264
Corporate	(11)	(16)	(26)	(28)	(30)
	409	362	1,574	1,434	1,241
Adjusted earnings per common share1	0.49	0.44	1.90	1.78	1.61
Cash flow data
Cash provided by operating activities	656	781	2,547	3,341	2,874
Cash used in investing activities	(3,737)	(3,277)	(11,891)	(9,431)	(6,204)
Cash provided by financing activities	3,221	2,744	9,770	5,070	4,395
Dividends
Common share dividends declared	297	261	1,177	1,035	895
Dividends paid per common share	0.350	0.315	1.40	1.26	1.13
Revenues
Commodity sales	6,192	6,939	28,281	26,039	18,494
Gas distribution sales	835	710	2,853	2,265	1,910
Transportation and other services	1,770	644	6,507	4,614	4,256
	8,797	8,293	37,641	32,918	24,660
Total assets	72,857	57,568	72,857	57,568	46,800
Total long-term liabilities	42,306	28,277	42,306	28,277	25,227

1 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 10.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Earnings attributable to common shareholders were $1,154 million ($1.39 per common share) for the year ended December 31, 2014 compared with $446 million ($0.55 per common share) for the year ended December 31, 2013 and $602 million ($0.78 per common share) for the year ended December 31, 2012. The Company has continued to deliver significant earnings growth from operations over the course of the last three years, as discussed below in Performance Overview – Adjusted Earnings. 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, the most significant of which is 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 exposures. The changes in unrealized mark-to-market accounting impacts from this program create volatility in short-term earnings, but the Company believes that over the long-term it supports the reliable cash flows and dividend growth upon which its investor value proposition is based. Earnings for 2014 and 2012 were also negatively impacted by the tax effect of 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 shares and partnership units, all tax consequences have remained in consolidated earnings and resulted in charges of $157 million and $56 million in 2014 and 2012, respectively. For further details, refer to Sponsored Investments – Enbridge Income Fund – Enbridge Income Fund Drop Down Transactions.

Also impacting the comparability of earnings year-over-year were costs and related insurance recoveries associated with the Line 6B crude oil release. Earnings for the years ended December 31, 2014, 2013 and 2012 included EEP’s cost estimates relating to the Line 6B crude oil release of US$86 million ($12 million after-tax attributable to Enbridge), US$302 million ($44 million after-tax attributable to Enbridge) and US$55 million ($8 million after-tax attributable to Enbridge), respectively. The aforementioned costs are before insurance recoveries and exclude potential additional fines and penalties other than the fines and penalties discussed under Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – Line 6B Crude Oil Release. For the years ended December 31, 2013 and 2012, EEP recognized insurance recoveries of US$42 million ($6 million after-tax attributable to Enbridge) and US$170 million ($24 million after-tax attributable to Enbridge), respectively, related to the Line 6B crude oil release. Refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – Insurance Recoveries. Within Liquids Pipelines, 2014 and 2013 earnings reflected remediation and long-term stabilization costs of approximately $4 million and $56 million after-tax and before insurance recoveries, respectively, related to the Line 37 crude oil release that occurred in June 2013. In 2014, Enbridge recognized insurance recoveries of $8 million after-tax related to the Line 37 crude oil release. Refer to Liquids Pipelines – Regional Oil Sands System – Line 37 Crude Oil Release.

Other significant items impacting the comparability of the Company’s year-over-year earnings were a $57 million after-tax gain recognized on the disposal of non-core assets within Enbridge Offshore Pipelines (Offshore) as well as a $14 million after-tax gain on the sale of an Alternative and Emerging Technologies investment within the Corporate segment. These transactions were recognized in 2014.

Finally, the Company’s 2013 earnings reflected certain out-of-period adjustments that also impact the comparability of earnings between years. The out-of-period adjustments included a non-cash adjustment of $37 million after-tax to defer revenues associated with make-up rights earned under certain long-term take-or-pay contracts within Regional Oil Sands System. Also in Regional Oil Sands System, there was an out-of-period adjustment of $31 million after-tax related to the recovery of income taxes under a long-term contract, partially offset by a related correction to deferred income tax expense. In Gas Distribution, an out-of-period adjustment of $56 million after-tax was recognized reflecting an increase to gas transportation costs which had incorrectly been deferred.

Fourth quarter performance drivers were largely consistent with year-to-date trends and 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 2014 included the impact of the tax effect associated with the transfer of assets between entities under common control of Enbridge, as noted above. Finally, the fourth quarter of 2014 included a $14 million after-tax gain recognized on the disposal of non-core assets within Offshore and leak insurance recoveries recognized from the June 2013 Line 37 crude oil release.

ADJUSTED EARNINGS

The Company’s investor value proposition focuses on visible growth, a reliable business model and a growing income 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 $1.61 per common share in 2012 to $1.78 per common share in 2013 and $1.90 per common share in 2014. This growth is a reflection of the strength of Enbridge’s existing asset portfolio combined with the successful execution of its large growth capital program, which saw a number of new assets placed into service over this period.

The combination of strong core assets and the successful execution of the growth capital program were particularly evident in the Company’s Liquids Pipelines and Sponsored Investments segments and were significant drivers of the Company’s overall adjusted earnings growth over the past three years. Within Liquids Pipelines, Canadian Mainline adjusted earnings growth was largely the result of higher throughput from growing crude oil supply from western Canada and higher downstream refinery demand. Additionally, successful efforts by the Company to optimize capacity and throughput and to enhance scheduling efficiency with shippers also drove an increase in throughput, most notably in 2014.

New Liquids Pipelines assets placed into service in the past three years within Regional Oil Sands System, including the Woodland and Wood Buffalo pipelines completed in late 2012 and the Norealis Pipeline completed in 2014, contributed to adjusted earnings growth. In the fourth quarter of 2014, the Company placed into service Flanagan South and Seaway Crude Pipeline System Twin (Seaway Pipeline Twin). The two projects are key components of the Company’s Gulf Coast Access program, which provides connectivity for producers in western Canada and the Bakken to the United States Gulf Coast refining hub. Both of the projects provided incremental earnings for the Company in the fourth quarter of 2014 and are expected to have a more significant impact on adjusted earnings growth in 2015.

Enbridge’s sponsored vehicles, EEP and the Fund, also contributed positively to adjusted earnings growth. EEP adjusted earnings reflected increased contributions from its liquids business due to 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 include the replacement and expansion of Line 6B as part of Enbridge and EEP’s Eastern Access Program. Enbridge also benefitted through its 75% interest in the United States portion of the Eastern Access expansion projects held through EELP. Within EEP’s natural gas and NGL businesses, which it holds directly and indirectly through its partially-owned subsidiary, Midcoast Energy Partners, L.P. (MEP), lower volumes had a negative impact on adjusted earnings. Within the Fund, adjusted earnings growth reflected the benefit of an increased asset base that resulted from Enbridge’s asset drop downs that occurred in 2011, 2012 and most recently in the fourth quarter of 2014.

Gas Pipelines, Processing and Energy Services 2014 adjusted earnings decreased compared with the previous year due in large part to market factors impacting the Company’s Energy Services businesses and Aux Sable facilities. Narrowing location spreads and less favourable conditions in certain markets accessed by committed transportation capacity, combined with unrecovered demand charges, resulted in lower adjusted earnings for Energy Services following a very strong 2013 fiscal year. Aux Sable adjusted earnings reflected a downward trend over the past two years due to lower fractionation margins and lower volumes at its upstream processing plants.

A key element of Enbridge’s strategy is to secure the longer-term future through developing new platforms for growth and diversification. Examples of diversification initiatives that drove year-over-year growth in adjusted earnings included the Company’s investment in Canadian Midstream assets, being the Cabin Gas Plant (Cabin) and the Pipestone and Sexsmith gathering systems (together, Pipestone and Sexsmith), as well as Enbridge’s continued investment in renewable energy assets through the acquisition of new wind farms and additional interests in existing wind farm assets that it owns with others.

The Company’s 2014 adjusted earnings were impacted by higher preference share dividends in its Corporate segment, as well as higher interest expense across various business segments reflecting incremental preference share and debt funding incurred to fund its growth capital program.

With respect to the fourth quarter of 2014, many of the annual trends discussed above were also the factors in driving adjusted earnings growth over the fourth quarter of 2013. In Liquids Pipelines, higher throughput on Canadian Mainline and new assets placed into service across the segment provided a favourable uplift to 2014 fourth quarter adjusted earnings. However, this growth was more than offset by a lower quarter-over-quarter toll on Canadian Mainline. In the fourth quarter of 2013, Regional Oil Sands System included a favourable adjustment related to a reduction in third party revenue sharing with the founding shipper on the Athabasca Pipeline. Although this adjustment had no impact on full year 2013 adjusted earnings, it resulted in higher adjusted earnings in the fourth quarter of 2013 compared with the equivalent 2014 period. Excluding the impact of this 2013 adjustment, Regional Oil Sands System adjusted earnings were comparable between the fourth quarter periods.

Energy Services earnings for the fourth quarter were higher than the comparable period in 2013 as wider location and crude grade differentials enabled it to capture more profitable margin and tank management arbitrage opportunities, which helped to partially offset the decrease in adjusted earnings during the first nine months of 2014 due to narrowing location spreads and less favourable conditions in certain markets accessed by committed transportation capacity, combined with unrecovered demand charges.

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 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 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 within these businesses and Enbridge’s partial ownership interest.

The latter half of 2014 has seen a dramatic decline in the price of crude oil, natural gas and NGL and other commodities whose prices are highly correlated to crude oil. Benchmark prices for crude which had been trading over US$105 per barrel in June 2014, fell to as low as US$53 per barrel by end of the year as a result of significant increases in production both inside and outside of North America in the face of relatively tepid growth in world-wide demand. Entering 2015, prices continue to be weak and are expected to remain volatile in the near-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 for 2015. However, this is not expected to materially impact the financial performance of the Company. Notwithstanding the price decline, it is expected that existing conventional and oil sands production should be more than sufficient to support continued high utilization of the liquids pipelines mainline. Entering 2015, 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 2018 and beyond. Importantly, after taking into account the potential for some of the less profitable 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 currently in progress will provide very cost-effective transportation services to key markets in North America.

In the current low-price environment, Enbridge is working closely with producers to find ways to enhance capacity and provide enhanced access to markets in order to alleviate locational pricing discounts. Examples include the Company’s recently completed Flanagan South and Seaway Pipeline Twin projects, which increase access to the United States Gulf Coast refining hub.

CASH FLOWS

Cash provided by operating activities was $2,547 million for the year ended December 31, 2014, mainly driven by strong operating performance from the Company’s core assets, particularly from Liquids Pipelines and Sponsored Investments, and the cash flow generation 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 2014, the Company was active in the capital markets with the issuance of $1,365 million in preference shares, common shares of approximately $478 million and $6,921 million in medium-term notes and also maintained its liquidity through 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 nearly $10 billion of projects placed into service in 2014 and are expected to provide financing flexibility for the Company’s growth capital program in 2015.

DIVIDENDS
The Company has paid common share dividends since it became a publicly traded company in 1953. In December 2014, the Company announced a 33% increase in its quarterly dividend to $0.465 per common share, or $1.860 annualized, effective March 1, 2015, in conjunction with the announcement of the Canadian Restructuring Plan. For more details, refer to Canadian Restructuring Plan.

Also in December 2014, Enbridge’s Board of Directors approved a revised dividend payout policy range of 75% to 85% of adjusted earnings. The previous payout policy range was 60% to 70%. In 2014, the dividend payout was 74% (2013 - 71%; 2012 - 70%) of adjusted earnings per share. The revised dividend policy is supported by the funding progress achieved to date and increasing internally generated free cash flow. For the 10-year period ended December 2014, the Company’s compound annual average dividend growth rate was 13.6%.

REVENUES

The Company generates revenues from three primary sources: commodity sales, gas distribution sales and transportation and other services. Commodity sales of $28,281 million for the year ended December 31, 2014 (2013 - $26,039 million; 2012 - $18,494 million) were generated 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.

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 and interest rates; the 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; final approval of definitive transfer terms by Enbridge and ENF and the Fund; receipt of all necessary shareholder and regulatory approvals that may be required for the Canadian Restructuring Plan; and weather. 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) or adjusted earnings/(loss) and associated per share amounts, the impact of the Canadian Restructuring Plan on Enbridge, the adjusted dividend payout policy or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service 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; and 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 operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, changes in tax law and tax rate increases, exchange rates, interest rates, commodity prices and supply and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

NON-GAAP MEASURES

This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. These factors, referred to as adjusting items, are reconciled and discussed in the financial results sections for the affected business segments. Adjusting items referred to as changes in unrealized derivative fair value gains or loss are presented net of amounts realized on the settlement of derivative contracts during the applicable period. Management believes the presentation of adjusted earnings/(loss) conveys useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/(loss) to set targets, including setting the Company’s dividend payout target, and to assess performance of the Company. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by U.S. GAAP and are not considered GAAP measures; therefore, these measures may not be comparable with similar measures presented by other issuers. The table below summarizes the reconciliation of the GAAP and non-GAAP measures.

NON-GAAP RECONCILIATIONS

	2014		2013		2012
(millions of Canadian dollars)
Earnings attributable to common shareholders	1,154		446		602
Adjusting items1:
Changes in unrealized derivative fair value and intercompany foreign exchange loss2	320		843		536
Make-up rights adjustments	17		50		-
Leak remediation costs, net of leak insurance recoveries	8		94		(15	)
Warmer/(colder) than normal weather	(36	)	(9	)	23
Gains on sale of non-core assets and investment	(71	)	(2	)	-
Asset impairment losses	2		6		105
Project development and transaction costs	14		-		-
Tax on intercompany gains on sale of assets	157		-		56
Tax related adjustments	-		(19	)	(9	)
Out-of-period adjustments	-		25		(1	)
Other	9		-		(56	)
Adjusted earnings	1,574		1,434		1,241

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.

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		· Strengthen core businesses

· Preserve financing strength and flexibility		· 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 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 (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. 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 $34 billion portfolio of commercially secured growth projects, successful project execution is critical to achieving the Company’s long-term growth plan. 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 maintain strong 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 program 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 2014, the Company announced its proposed Canadian Restructuring Plan, which will transfer the majority of its Canadian Liquids Pipelines business and certain renewable energy assets to the Fund. 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, analyzed 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 continue to be focused on providing access to new markets for growing production from western Canada and Bakken regions, optimizing and expanding mainline operations and expanding regional oil sands infrastructure. The Company’s assets are strategically located and well-positioned to capitalize on these opportunities. Over the past year, Enbridge has significantly advanced its market access programs that provide shippers with greater connectivity to key markets and secure more favourable pricing for their products. In 2014, the Company significantly advanced its Gulf Coast Access program through the completion of Flanagan South and Seaway Pipeline Twin. Combined, the two projects have the capability of providing up to 600,000 barrels per day (bpd) of incremental capacity to transport crude oil from the oil sands or Bakken regions to the key United States Gulf Coast refining hub. Enbridge continued to optimize and expand its mainline system and in 2014, throughput reached record levels driven by strong supply and refinery demand in combination with efforts by the Company to maximize capacity and throughput and to enhance scheduling efficiency with shippers. As new projects come into service, one of the key objectives is to fully integrate them within Enbridge’s existing portfolio.

While executing its record growth capital program, the Company has also been undertaking an extensive integrity program across its liquids and gas systems. In addition, in 2014, Enbridge completed the replacement of Line 6B and an in-depth inspection of Line 9B as part of the Line 9B reversal and expansion project. Also in 2014, the Company announced the Line 3 Replacement Program (L3R Program). While the L3R Program will not increase the overall capacity of the mainline system, 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.

The focus in Regional Oil Sands Systems is to optimize existing asset corridors to secure incremental supply expected from the western Canadian oil sands projects over the next decade. Within this regional focus area, Enbridge has approximately $6 billion of regional infrastructure currently under development which is expected to enter service from 2014 to 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). Due to be placed into service in 2017, Sandpiper will provide North Dakota producers enhanced access to premium light crude oil markets.

With the majority of the Company’s growth capital projects expected to come into service by the end of 2018, the Company’s liquids business is also carrying out initiatives to secure and extend the growth beyond 2018. The proposed structure announced in the Canadian Restructuring Plan is expected to help position the Company to support future investments and extend growth past 2018 by improving the competitiveness of its funding costs for new organic growth opportunities and asset acquisitions. For further details on the Canadian Restructuring Plan, refer to Canadian Restructuring Plan.

The Company’s natural gas strategies include leveraging the competitive advantages of its existing assets and expanding its footprint in emerging areas. Combined, Alliance Pipeline and the Aux Sable NGL 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 also made significant progress in securing precedent agreements with shippers past December 2015 when the majority of its existing contracts are set to expire. For further details, refer to Sponsored Investments — Enbridge Income Fund — Alliance Pipeline Recontracting.

The Company expanded its Canadian midstream infrastructure in 2014 with the completion of the Pipestone and Sexsmith projects which included sour gas gathering and compression facilities located in the Peace River Arch (PRA) region of northwest Alberta. The Company is seeking to expand its Canadian midstream footprint, with the primary focus in the liquids-rich Montney and Duvernay formations in western Canada. In addition to these onshore strategies, the Company continues to pursue crude oil and natural gas gathering pipeline opportunities for ultra-deep projects in the Gulf of Mexico. In the fourth quarter of 2014, the Company placed the Jack St. Malo portion of the Walker Ridge Gas Gathering System (WRGGS) into service and expects to place the Big Foot gas portion of WRGGS along with the Big Foot Oil Pipeline (Big Foot Pipeline) into service in the third quarter of 2015. Growth in Offshore is expected to continue as the Heidelberg Oil Pipeline (Heidelberg Pipeline) is currently under construction and is expected to enter service in 2016. Additionally, in early January 2015, the Company announced it was selected to build, own and operate the Stampede Oil Pipeline (Stampede Pipeline), a crude oil pipeline in the Gulf of Mexico to connect to Hess Corporations’ (Hess) Stampede development.

Enbridge’s natural gas distribution business in eastern Canada is the largest in Canada with over two million customers. In 2014, the Ontario Energy Board (OEB) approved the second generation customized Incentive Rate (IR) Plan which establishes 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 Greater Toronto Area (GTA) Project which will increase capacity and reliability for EGD’s customers and diversify gas supply. 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 provides stability in earnings and cash flow to Enbridge’s overall business model.

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 and power transmission facilities and in energy marketing, as well as developing opportunities in gas-fired power generation, liquefied natural gas (LNG) development and select energy delivery assets outside North America. The Company also invests in early stage energy technologies that complement the Company’s core businesses.

Since the end of 2013, Enbridge has continued to grow its renewable power portfolio, placing into service Blackspring Ridge in Alberta and the Keechi Wind Project (Keechi) in Texas. The Company also increased its interest in the 300-MW Lac Alfred to 67.5% and in the 150-MW Massif du Sud to 80%. Late in 2014, Enbridge finalized the purchase of an 80% interest in a portfolio of two wind farms located in Texas and Indiana. With the closing of this transaction, Enbridge’s enterprise-wide renewable energy portfolio has a net generation capacity of approximately 1,600 MW.

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 with 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 the public’s trust, and to 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 G3.1 sustainability reporting guidelines, which serve as a generally accepted framework for reporting on an organization’s economic, environmental and social performance.

An important component of CSR at Enbridge is the Neutral Footprint Program. Through Enbridge’s Neutral Footprint Program, the Company has committed to reducing the environmental impact of its pipeline expansion projects within five years of their occurrence. The Company seeks to meet this commitment by:

· planting a tree for every tree the Company removes;

· conserving an acre of natural habitat for every acre the Company permanently alters; and

· growing the Company’s renewable energy business at a pace that matches increased energy consumption in its liquids pipelines business through generation of an additional kilowatt hour of renewable energy for every additional kilowatt hour of energy used to power its pipeline projects.

Since it began five years ago, the Neutral Footprint Program has met its targets for trees, hectares and kilowatt hours, and in 2014 continued to be on track to do so. In 2014, the Company also consulted with internal and external stakeholders on the purpose and design of the program moving forward. In 2015, the Company plans to update the program to address the feedback it has received and incorporate new approaches to engaging with its Right of Way Communities on environmental conservations projects and opportunities.

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 at http://www.enbridge.com/neutralfootprint and 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. The Company continues to focus on people-related areas, including broadening recruiting efforts beyond traditional industry and geographical reaches, ensuring succession capability through accelerated leadership development programs and enhancing career opportunities and building change management capabilities throughout the enterprise to ensure projects and initiatives achieve the 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. The international market for crude oil has seen a significant change in the supply including a significant increase in production from North American basins and increased production from Organization of the Petroleum Exporting Countries (OPEC). The reduction in price has had an impact on Enbridge’s liquids pipelines’ customers, who have responded by reducing their exploration and development spending for 2015.

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, as nominated volumes currently exceed current capacity on the system. Any impact to the financial performance of Enbridge’s liquids pipelines business is expected to be relatively modest given the commercial arrangements which underpin the system and provide a significant measure of protection in a falling supply scenario. 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 of oil sands production suggest that long-term supply growth from the WCSB will not change materially.

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 non-Organisation for Economic Co-operation and Development (OECD) regions, such as China, India and the Middle East. In OECD countries, including Canada, the United States and western European nations, efficiency gains, conservation, limited population growth and a shift to alternative energy 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 2040, with North America being a significant contributor to overall global supply. Growth in North America is largely driven by production from the oil sands, the Gulf of Mexico and the emergence and continued development of tight oil plays including the Bakken, Eagle Ford and Permian formations. Political uncertainty in certain oil producing countries, including Libya, Iran, Syria and Iraq, risk those regions’ supply growth forecast and makes North America one of the more secure supply sources of crude oil. As witnessed in the latter half of 2014, 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. In Canada, the WCSB is viewed as one of the world’s largest and most secure supply sources of crude oil. Investment in the WCSB is expected to remain strong over the longer-term due to technological advances and continued foreign investment. However, the pace of growth in North America could be tempered by a sustained period of low crude oil prices, as well as increasing environmental regulation in future years.

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 has 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 has resulted in a further discounting of Alberta crude against WTI. With a number of market access initiatives recently taken by the industry, including those introduced by Enbridge, the crude oil price differentials significantly narrowed in 2014 and resulted in higher netbacks for producers. However, 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. Shippers also continue to seek alternative means of transportation, such as rail, to access higher netback markets as a result of a shortage of pipeline capacity; however, 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. In 2014, Enbridge reached a significant milestone in its Gulf Coast Access Program through the completion of Flanagan South and Seaway Pipeline Twin. Together, these projects have the capability of opening up to approximately 600,000 bpd of capacity to transport crude from the oil sands and Bakken regions to the United States Gulf Coast refining area. Significant steps were also achieved in the Company’s Eastern Access Program, with the completion of the Line 6B replacement and expansion project in September 2014. The Eastern Access Program provides increased access to refineries in the upper midwest United States and eastern Canada.

As oil sands production in western Canada continues to grow, prices continue to be sensitive to capacity limitations to markets, heightening the need to expand access to growing Asian 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 Growth Projects – Commercially Secured Projects and Growth Projects – Other Projects Under Development.

SUPPLY AND DEMAND FOR NATURAL GAS AND NGL

Global energy demand is expected to increase as the global economy grows with most of this growth expected from non-OECD countries. Natural gas will play an important role to meet 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; 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 projected to be modest until the next wave of gas-intensive petrochemical facilities, LNG export facilities and gas-fired generation enters service, which is expected later this decade. Over the longer-term, higher United States natural gas demand is expected to be driven by the industrial sector and from power generation. Within Canada, natural gas demand growth is expected to be largely tied to oil sands development.

Similar to crude oil, robust North American supply from tight formations has created a demand and supply imbalance. North American supply continues to be dominated by natural gas development in the northeastern United States, primarily the dominant Marcellus shale, as well as the emerging Utica shale. The abundance of supply from these shale plays has fundamentally altered natural gas flow patterns in North America and largely displaced United States Gulf Coast and WCSB gas production. As a result, regional natural gas production, apart from the abundant production in the northeastern United States, has largely been flat or has declined over the past several years in response to robust growth in the Appalachian region and resulted in prolonged weak North American natural gas prices. While low natural gas prices are expected to be a key driver in future infrastructure growth and natural gas demand, 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 have 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. Over the longer-term, the growth in NGL demand will be largely driven by ethane demand as it is the key feedstock to the United States Gulf Coast petrochemical industry which is currently undergoing significant expansion and once completed is expected to be the world’s second lowest-cost ethylene producer. However, until this infrastructure is established, ethane prices and resulting extraction margins are expected to remain low due to the current oversupply and have resulted in ethane being retained in the gas stream rather than processed. Rapidly growing supplies of propane have also been placing downward pressure on prices and have prompted the expansion of export facilities. In Canada, the WCSB basin is well-situated to capitalize on the evolving NGL fundamentals as the Montney formation in northern British Columbia and the Duvernay shale in Alberta have significant liquids-rich resources at competitive costs. While longer-term NGL fundamentals suggest 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.

The recent decline in crude prices has had a direct impact on producers’ oil focused drilling plans in 2015. Lower prices for NGL, which generally trade at a percentage of crude prices, will also cause a reduction in liquids-rich gas drilling and limit production growth. However, robust gas production from highly economic core areas within certain shale plays, particularly the Marcellus, is expected to offset any price related production declines 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 continue to limit price increases. In this scenario, the crude-to-gas price ratio is expected to remain well above energy conversion value levels and continue to be supportive of NGL extraction.

The price for LNG in global markets has typically been more closely linked to crude oil prices, providing producers with an opportunity to capture more favourable netbacks on LNG exports from North America, 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 increasing probability that additional projects to export LNG from the continental United States or potentially off the west Coast of Canada will proceed. 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 configured to transport liquids-rich gas. Alliance Pipeline has developed new service offerings to best meet the needs of producers and shippers. 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 electrical generation and distribution network in North America is expected to undergo significant growth over the next 15 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 a core component 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 are nearly 66 gigawatts (GW) of installed wind power capacity and in Canada over nine 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 16 GW of installed solar photovoltaic capacity. 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. Furthermore, the profitability of renewable energy projects, to date, has in part been supported by certain tax and government incentives. In the near-term, uncertainty over the continuing availability of tax or other government incentives and the ability to secure long-term power purchase agreements (PPA) through government or investor-owned power authorities 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.

Enbridge continues to expand its renewable asset footprint and is Canada’s second-largest wind power generator and second-largest solar power generator. Since the end of 2013, Enbridge placed into service the Blackspring Ridge and Keechi wind farms and also increased its ownership interest in Lac Alfred to 67.5% and in Massif du Sud to 80%. Late in 2014, Enbridge also finalized the purchase of an 80% interest in a portfolio of two wind farms located in Texas and Indiana from E.ON Climate and Renewables North America, LLC (E.ON), a subsidiary of E.ON SE. The Company will continue to seek new opportunities to grow its portfolio of renewable power generation businesses 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 2014, Enbridge successfully placed into service approximately $10 billion of growth projects across several business units. Enbridge also expanded its portfolio of commercially secured growth projects to $34 billion. All of these projects are expected to come into service by 2018; with more than $9 billion during 2015.

Enbridge’s growth capital program is 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 extensions. The three major market access initiatives are:

· the Gulf Coast Access Program;

· the Eastern Access Program; and

· the Light Oil Market Access Program.

In 2014, the Company made significant strides in its market access initiatives. In December 2014, Enbridge placed into service Flanagan South and Seaway Pipeline Twin, two key components of its Gulf Coast Access Program. Significant progress was also made in the Company’s Eastern Access Program with the completion of the Line 6B replacement and expansion project in September 2014.

The $5.4 billion Gulf Coast Access Program includes Seaway Pipeline, Seaway Pipeline Twin, Flanagan South and elements of the Canadian Mainline and Lakehead System Mainline expansions and will increase access to refinery markets in the Gulf Coast. The $2.7 billion Eastern Access Program is expected to allow for greater access for crude oil into Chicago, further east into Toledo and ultimately into Ontario and Quebec. The Eastern Access Program includes the Company’s Toledo pipeline expansion, Line 9 reversal, the existing Spearhead North pipeline expansion, Line 6B replacement and Line 5 expansion. Finally, the $6 billion Light Oil Market Access Program brings together a group of projects to support the increasing supply of light oil from Canada and the Bakken and also supplements the Eastern Access Program through the upsize of the Line 9B and Line 6B capacity expansion. The Light Oil Market Access Program also includes the Southern Access Extension Project (Southern Access Extension), Sandpiper, Canadian Mainline System Terminal Flexibility and Connectivity, twinning of the Spearhead North pipeline (Spearhead North Twin) and Southern Access expansion included within the Lakehead System Mainline Expansion.

In 2014, Enbridge announced the $7.5 billion L3R Program, the largest growth capital project in the Company’s history. The L3R Program will support the safety and operational reliability of the Company’s mainline system as well as enhance the flexibility and optimize throughput. The Company also has approximately $6 billion in regional infrastructure projects under development, solidifying its position as the largest pipeline operator in the oil sands region of Alberta.

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 2014. With the purchase of additional interest in the Lac Alfred and Massif du Sud wind farms along with the acquisition of interests in two producing wind farms in the United States, Enbridge increased its net generating capacity to approximately 1,600 MW.

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. Seaway Crude Pipeline System Twinning/Extension	US$1.2 billion	US$1.2 billion	2014	Complete

2. Eastern Access Line 9 Reversal and Expansion	$0.7 billion	$0.6 billion	2013-2015 (in phases)	Substantially Complete

3. Eddystone Rail Project	US$0.1 billion	US$0.1 billion	2014	Complete

4. Norealis Pipeline	$0.5 billion	$0.5 billion	2014	Complete

5. Flanagan South Pipeline Project	US$2.9 billion	US$2.8 billion	2014	Complete

6. Canadian Mainline Expansion	$0.7 billion	$0.5 billion	2015	Under Construction
7. Surmont Phase 2 Expansion	$0.3 billion	$0.2 billion	2014-2015 (in phases)	Under construction
8. Canadian Mainline System Terminal Flexibility and Connectivity	$0.7 billion	$0.4 billion	2013-2015 (in phases)	Under construction
9. Sunday Creek Terminal Expansion	$0.2 billion	$0.2 billion	2015	Under construction
10. Woodland Pipeline Extension	$0.6 billion	$0.5 billion	2015	Under construction
11. Edmonton to Hardisty Expansion	$1.8 billion	$1.1 billion	2015	Under construction
12. Southern Access Extension	US$0.6 billion	US$0.2 billion	2015	Under- construction
13. AOC Hangingstone Lateral	$0.2 billion	No significant expenditures to date	2015	Under- construction
14. JACOS Hangingstone Project	$0.2 billion	No significant expenditures to date	2016	Pre- construction

	Estimated Capital Cost1	Expenditures to Date2	Expected In-Service Date	Status
15. Athabasca Pipeline Twinning	$1.2 billion	$1.1 billion	2017	Under construction
16. Wood Buffalo Extension	$1.6 billion	$0.1 billion	2017	Pre- construction
17. Norlite Pipeline System3	$1.4 billion	No significant expenditures to date	2017	Pre- construction
18. Canadian Line 3 Replacement Program	$4.9 billion	$0.3 billion	2017	Pre- construction
GAS DISTRIBUTION
19. Greater Toronto Area Project	$0.8 billion	$0.2 billion	2015	Under construction
GAS PIPELINES, PROCESSING AND ENERGY SERVICES
20. Pipestone and Sexsmith Project	$0.3 billion	$0.3 billion	2012-2014 (in phases)	Complete
21. Blackspring Ridge Wind Project	$0.3 billion	$0.3 billion	2014	Complete
22. Magic Valley and Wildcat Wind Farms	US$0.3 billion	US$0.3 billion	2014	Acquisition closed
23. Keechi Wind Project	US$0.2 billion	US$0.2 billion	2015	Complete
24. Walker Ridge Gas Gathering System	US$0.4 billion	US$0.3 billion	2014-2015 (in phases)	Under construction
25. Big Foot Oil Pipeline	US$0.2 billion	US$0.2 billion	2015	Under construction
26. Aux Sable Extraction Plant Expansion	US$0.1 billion	No significant expenditures to date	2016	Pre- construction
27. Heidelberg Oil Pipeline	US$0.1 billion	US$0.1 billion	2016	Under construction
28. Stampede Oil Pipeline	US$0.2 billion	No significant expenditures to date	2018	Pre- construction
SPONSORED INVESTMENTS
29. EEP - Line 6B 75-Mile Replacement Program	US$0.4 billion	US$0.4 billion	2013-2014 (in phases)	Complete
30. EEP - Eastern Access4	US$2.7 billion	US$2.1 billion	2013-2016 (in phases)	Under construction
31. EEP - Lakehead System Mainline Expansion4	US$2.3 billion	US$1.1 billion	2014-2017 (in phases)	Under construction
32. EEP - Beckville Cryogenic Processing Facility	US$0.1 billion	US$0.1 billion	2015	Under construction
33. EEP - Eaglebine Gathering	US$0.2 billion	No significant expenditures to date	2015-2016 (in phases)	Under construction
34. EEP - Sandpiper Project5	US$2.6 billion	US$0.4 billion	2017	Pre- construction
35. EEP - U.S. Line 3 Replacement Program	US$2.6 billion	US$0.2 billion	2017	Pre- construction

1 These amounts are estimates and 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, 2014.

3 Enbridge will construct and operate the Norlite Pipeline System. Keyera Corp. 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 Enbridge will construct and operate the Sandpiper Project. Marathon Petroleum Corporation 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

Seaway Pipeline

Enbridge holds a 50% interest in the Seaway Pipeline which includes an 805-kilometre (500-mile), 30-inch diameter long-haul system between Cushing, Oklahoma and Freeport, Texas.

Reversal and Expansion

The flow direction of the Seaway Pipeline was reversed in 2012, enabling it to transport crude oil 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 150,000 bpd to up to approximately 400,000 bpd, depending on crude oil slate.

Twinning and Extension

Seaway Pipeline Twin was constructed in order to more than double the existing capacity of Seaway Pipeline to approximately 850,000 bpd and was mechanically completed in July 2014. Seaway Pipeline Twin was placed into service in December 2014 following the completion of Flanagan South. See Growth Projects – Commercially Secured Projects – Liquids Pipelines – Flanagan South Pipeline Project. This 30-inch diameter pipeline follows the same route as the existing Seaway Pipeline and was constructed to meet additional capacity commitments from shippers. Included in the project scope is the 105-kilometre (65-mile), 36-inch diameter pipeline lateral from the Seaway Jones Creek facility southwest of Houston, Texas to Enterprise Product Partners L.P.’s ECHO crude oil terminal (ECHO Terminal) in Houston, Texas. The lateral was placed into service in January 2014.

In addition, a 161-kilometre (100-mile) pipeline was constructed from the ECHO Terminal to the Port Arthur/Beaumont, Texas refining centre to provide shippers access to the region’s heavy oil refining capabilities. This extension provides capacity of 750,000 bpd and was mechanically completed in August 2014 and placed into service in January 2015.

Including the acquisition of the initial 50% interest, Enbridge’s total cost for Seaway Pipeline is approximately US$2.5 billion. The acquisition, reversal and expansion were completed at an approximate cost of US$1.3 billion, with the twinning, extension and lateral components of the project completed at an approximate cost of US$1.2 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 being undertaken by Enbridge include a reversal of Line 9A, a reversal of Line 9B and expansion of Line 9 (together, Line 9) and expansion of the Toledo Pipeline. 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.

In 2013, Enbridge completed the 80,000 bpd expansion of its Toledo Pipeline (Line 17), which connects with the EEP mainline at Stockbridge, Michigan and serves refineries at Toledo, Ohio and Detroit, Michigan. The project was completed at an approximate cost of US$0.2 billion.

In 2013, Enbridge also completed the reversal of Line 9A in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario. Enbridge is also undertaking a 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 within Ontario and Quebec, resulting in the Line 9 capacity expansion project. The Line 9 capacity expansion will increase 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 Project was 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, Enbridge 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, which is a prerequisite to allowing the operation of the project. Subject to NEB approval for the Leave to Open application, Enbridge expects to place the Line 9B Reversal and Line 9 Capacity Expansion Project into service in the second quarter of 2015. In its February approval, the NEB also imposed additional obligations on Enbridge that direct the Company to take a “life-cycle” approach to water crossings and valves, requiring the Company performs ongoing analysis and rationale to ensure optimal protection of the area’s water resources.

The conditions previously imposed by the NEB, including costs associated with additional NEB mandated integrity testing, increased the total expected cost of the projects to $0.7 billion, inclusive of costs related to the previously discussed Line 9A reversal. Enbridge has recently reached an agreement with shippers to recover a portion of the incremental cost of additional valves ordered by the NEB through a toll surcharge. Total expenditures to date on the Line 9A and Line 9B projects are approximately $0.6 billion.

On July 31, 2014, Enbridge filed an application for tolls for 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, Enbridge requested that the NEB approve the tolls on an interim basis to allow for time to engage shippers in further discussions to attempt to resolve the outstanding issues. The NEB established interim tolls, which remain in effect and in late 2014, Enbridge and shippers filed letters with the NEB requesting that it establish a process to consider the issues. The NEB has set a written hearing with oral reply argument to be heard on May 28, 2015.

Eddystone Rail Project

In April 2014, under a joint venture agreement with Canopy Prospecting Inc., the Company completed the development of a unit-train unloading facility and related local pipeline infrastructure near Philadelphia, Pennsylvania to deliver Bakken and other light sweet crude oil to Philadelphia area refineries. Eddystone Rail Project (Eddystone) is capable of receiving and delivering an initial capacity of 80,000 bpd and could be expanded to 160,000 bpd. Based on its 75% joint venture interest, Enbridge’s investment in the project was approximately US$0.1 billion.

Norealis Pipeline

In order to provide pipeline and terminalling services to the Husky Energy Inc. operated Sunrise Energy Project that is currently under development, Enbridge constructed a new originating terminal (Norealis Terminal), a 112-kilometre (66-mile), 24-inch diameter pipeline from the Norealis Terminal to the Cheecham Terminal and additional tankage at Cheecham. The Norealis Pipeline project was completed in April 2014 at a total cost of approximately $0.5 billion. Enbridge transferred diluent into the Norealis Terminal in the fourth quarter of 2014 and receipt of blend product is expected in the second quarter of 2015.

Flanagan South Pipeline Project

The 950-kilometre (590-mile) pipeline has an initial design capacity of approximately 600,000 bpd; however, in the initial years, it is not expected to operate at its full design capacity. Flanagan South will transport crude oil from the Company’s terminal at Flanagan, Illinois to Cushing, Oklahoma. The 36-inch diameter pipeline is installed adjacent to the Company’s Spearhead Pipeline for the majority of the route. The pipeline was placed in-service on December 1, 2014 and the total cost of the project is now US$2.9 billion. Final expenditures will be incurred into 2015, with expenditures to date of approximately US$2.8 billion.

The Sierra Club and National Wildlife Federation (the Plaintiff) filed a complaint (the Complaint) for Declaratory and Injunctive Relief with the United States District Court for the District of Columbia (the Court) in August 2013. The Complaint was filed against multiple federal agencies (the Defendants) and included a request that the Court issue a preliminary injunction suspending previously granted federal permits and ordering Enbridge to discontinue construction of the project on the basis that the Defendants failed to comply with environmental review standards of the United States’ National Environmental Policy Act (NEPA). Enbridge obtained intervenor status and joined the Defendants in filing a response in opposition to the motion for preliminary injunction in September 2013. The Plaintiff’s request for preliminary injunction was denied by the Court in November 2013. A court hearing was held on February 21, 2014 concerning the merits of the Complaint against the Defendants, and on August 18, 2014, the Court ruled to dismiss all claims in favour of Enbridge and the Defendants. The Sierra Club filed an appeal to the United States Court of Appeals for the District of Columbia Circuit in mid-August 2014 and filed its opening brief on December 23, 2014. Enbridge and the Defendants filed their briefs on January 22, 2015. The Sierra Club’s reply brief was filed on February 8, 2015 and an oral argument will be subsequently scheduled.

Canadian Mainline Expansion

Enbridge is undertaking an expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba. The scope of the project consists of two phases that involve 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 mechanically completed in the third quarter of 2014 at an estimated capital cost of approximately $0.2 billion. Delays in receipt of the applicable regulatory approvals on EEP’s portion of the mainline system expansion are expected to delay the full operation of the first phase of the Canadian Mainline Expansion. However, a number of temporary system optimization actions are being undertaken to substantially mitigate any impact on throughput associated with the initial 120,000 bpd capacity increase. See Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Mainline Expansion.

The second phase to increase capacity from 570,000 bpd to 800,000 bpd is expected to be placed into service in 2015. The second phase is expected to cost approximately $0.5 billion, following the completion of a detailed engineering review conducted in the first quarter of 2014. The revised estimate reflected enhanced tanking, terminalling and connectivity to optimize pipeline operation at the full 800,000 bpd design capacity. The estimated cost of the entire expansion is approximately $0.7 billion, with expenditures to date of approximately $0.5 billion.

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 is constructing two new 450,000 barrel blend tanks and converting an existing tank from blend to diluent service. The expansion is planned in two phases with the blended product system placed into service in November 2014 and the diluent system expected to be completed in the first quarter of 2015. The estimated cost of the project is approximately $0.3 billion, with expenditures to date of approximately $0.2 billion.

Canadian Mainline System Terminal Flexibility and Connectivity

As part of the Light Oil Market Access Program initiative, the Company is undertaking 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 are comprised of upgrading existing booster pumps, additional booster pumps and new tank line connections. These projects have varying completion dates from 2013 through the second quarter of 2015. The cost of the project is expected to be approximately $0.7 billion, following the completion of a detailed engineering review. The revised estimate reflects enhanced tankage, terminalling and connectivity in conjunction with the Company’s Canadian Mainline Expansion project. Refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Canadian Mainline Expansion. Expenditures to date total approximately $0.4 billion.

Sunday Creek Terminal Expansion

In January 2014, the Company announced it will construct 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 includes 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 estimated cost for the expansion is approximately $0.2 billion, with expenditures to date of approximately $0.2 billion and a targeted in-service date in the third quarter of 2015.

Woodland Pipeline Extension

The joint venture Woodland Pipeline Extension Project will extend the Woodland Pipeline south from Enbridge’s Cheecham Terminal to its Edmonton Terminal. The extension is a proposed 388-kilometre (241-mile), 36-inch diameter pipeline with an initial capacity of 400,000 bpd, expandable to 800,000 bpd. After finalization of scope and a definitive cost estimate, Enbridge’s share of the estimated capital cost of the project is approximately $0.6 billion, with expenditures incurred to date of approximately $0.5 billion. The project has a target in-service date of the third quarter of 2015.

Edmonton to Hardisty Expansion

The Company is undertaking an expansion of the Canadian Mainline system between Edmonton, Alberta and Hardisty, Alberta. The expansion project will include 181 kilometres (112 miles) of new 36-inch diameter pipeline and will provide an initial capacity of approximately 570,000 bpd, expandable to 800,000 bpd. The new line is expected to generally follow the same route as Enbridge’s existing Line 4 pipeline. Also included in the project scope are connections into existing infrastructure at the Hardisty Terminal and new terminal facilities in Edmonton which include five new 500,000 barrel tanks. The new pipeline is expected to be placed into service in the first quarter of 2015, with additional tankage requirements expected to be completed by the fourth quarter of 2015, all at an expected total cost of approximately $1.8 billion. Expenditures incurred to date are approximately $1.1 billion.

Southern Access Extension

Southern Access Extension involves 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. Effective July 1, 2014, the Company entered into an agreement with Lincoln Pipeline LLC (Lincoln), an affiliate of Marathon Petroleum Corporation (MPC), to, among other things, admit Lincoln as a partner and participate in Southern Access Extension. Lincoln has purchased a 35% equity interest in the project and will make additional cash contributions in accordance with the Southern Access Extension spend profile in proportion to its 35% interest. Subject to regulatory and other approvals, the project is expected to be placed into service in the fourth quarter of 2015. Southern Access Extension is expected to cost approximately US$0.9 billion, with Enbridge’s share of the estimated capital cost expected to be approximately US$0.6 billion. Enbridge’s expenditures to date on the project are approximately US$0.2 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 will involve the construction of a new 49-kilometre (31-mile), 16-inch diameter pipeline from the AOC Hangingstone project site to Enbridge’s existing Cheecham Terminal and related facility modifications at Cheecham. Phase I of the project will provide an initial capacity of 16,000 bpd and is expected to be placed into service in the fourth quarter of 2015, to align with shipper volume availability, at an estimated 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

Enbridge will undertake the construction of facilities and 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. Subject to regulatory approvals, Enbridge plans to construct a new 53-kilometre (33-mile), 12-inch lateral pipeline to connect the JACOS Hangingstone project site to Enbridge’s existing Cheecham Terminal. The project, which will provide capacity of 40,000 bpd and is expected to enter service in 2016, is now estimated to cost approximately $0.2 billion.

Athabasca Pipeline Twinning

This project involves twinning the southern section of the Athabasca Pipeline from Kirby Lake, Alberta to the Hardisty, Alberta crude oil hub to provide additional capacity to serve expected oil sands growth in the Kirby Lake producing region. The expansion project, with an estimated cost of approximately $1.2 billion, and expenditures to date of approximately $1.1 billion, will include 346 kilometres (215 miles) of 36-inch diameter pipeline adjacent to the existing Athabasca Pipeline right-of-way. The line is expected to be delayed beyond its original in-service date and is now expected to be completed in 2017 due to a change in the construction schedule to align with shipper volume availability.

Wood Buffalo Extension

In 2013, Enbridge was selected by Suncor Energy Inc., Total E&P Canada Ltd. and Teck Resources Limited (the Fort Hills Partners), as well as the Suncor Energy Oil Sands Limited Partnership (Suncor Partnership), to develop a new pipeline to transport crude oil production to Enbridge’s mainline hub at Hardisty, Alberta. The proposed Wood Buffalo Extension will extend Enbridge’s existing Wood Buffalo Pipeline and includes construction of a new 450-kilometre (281-mile), 30-inch pipeline from Enbridge’s Cheecham Terminal to its Battle River Terminal at Hardisty, as well as associated terminal upgrades. The completed project will provide capacity of 490,000 bpd of diluted bitumen to be transported for the proposed Fort Hills Partners’ oil sands project (Fort Hills Project) in northeastern Alberta and Suncor Partnership’s oil sands production in the Athabasca region. Subject to regulatory approvals, the project is expected to be completed in 2017 at an estimated cost of approximately $1.6 billion, with expenditures incurred to date of approximately $0.1 billion.

Norlite Pipeline System

Enbridge is undertaking the development of Norlite Pipeline System (Norlite), a new industry diluent pipeline originating from Edmonton 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 both 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 Enbridge’s Stonefell Terminal to its Cheecham Terminal with an extension to Suncor Partnership’s East Tank Farm, which is adjacent to Enbridge’s existing Athabasca Terminal. Under an agreement with Keyera Corp. (Keyera), Norlite has the right to access certain existing capacity on Keyera’s pipelines between Edmonton and Stonefell and, in exchange, Keyera has elected to participate in the new pipeline infrastructure project as a 30% non-operating owner. Subject to regulatory and other approvals as well as finalization of scope, Norlite is expected to be completed in 2017 at an estimated cost of approximately $1.4 billion.

Canadian Line 3 Replacement Program

In March 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. The Canadian portion of the Line 3 Replacement Program (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. The L3R Program is expected to achieve an equivalent 34-inch diameter pipeline capacity of approximately 760,000 bpd, which will enhance the flexibility and reliability of the Enbridge mainline system’s overall western Canada export capacity.

Subject to regulatory and other approvals, the Canadian L3R Program is targeted to be completed in late 2017. Following the completion of a definitive cost estimate in the second quarter of 2014, the estimated capital cost of the Canadian L3R Program is approximately $4.9 billion, with expenditures to date of approximately $0.3 billion. Costs of the Canadian L3R Program will be recovered through a 15-year toll surcharge mechanism under the Competitive Toll Settlement (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.

GAS DISTRIBUTION

Greater Toronto Area Project

EGD will undertake 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 will involve the construction of two new segments of pipeline, a 27-kilometre (17-mile), 42-inch diameter pipeline and a 23-kilometre (14-mile), 36-inch diameter pipeline in Toronto, Ontario, as well as related facilities to upgrade the existing distribution system that delivers natural gas to several municipalities in Ontario. With the OEB approval received in January 2014, construction began in January 2015 and completion of the project is expected in the fourth quarter of 2015 at a now estimated cost of approximately $0.8 billion, with expenditures to date of approximately $0.2 billion.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Pipestone and Sexsmith Project

In 2012, the Company acquired from Encana Corporation (Encana) Pipestone and Sexsmith, which consist of certain sour gas gathering and compression facilities in the PRA region of northwest Alberta. These facilities were either in service (Sexsmith) or under construction (Pipestone) at the time of acquisition. Construction of new gathering lines and NGL handling facilities was completed in June 2014. Enbridge’s investment in Pipestone and Sexsmith is approximately $0.3 billion. Enbridge also retains an exclusive right to work with Encana on facility scoping for development of additional major midstream facilities in the liquids-rich PRA region.

Blackspring Ridge Wind Project

In 2013, Enbridge secured a 50% interest in the development of the 300-MW Blackspring Ridge, located 50 kilometres (31 miles) north of Lethbridge, Alberta in Vulcan County. The project was constructed under a fixed price engineering, procurement and construction contract and commercial operations commenced in May 2014. Renewable Energy Credits generated from Blackspring Ridge are contracted to Pacific Gas and Electric Company under a 20-year purchase agreement. The electricity is being sold into the Alberta power pool with pricing fixed on 75% of production through long-term price swap arrangements. The Company’s total investment in the project is approximately $0.3 billion.

Magic Valley and Wildcat Wind Farms

In November 2014, Enbridge announced it had entered into an agreement with E.ON to purchase an 80% interest in a wind farm portfolio which included the 203-MW Magic Valley 1 wind farm located near Harligen, Texas and the 202-MW Wildcat 1 wind farm near Elwood, Indiana for approximately US$0.3 billion. Both wind farms are operational and were placed into service in 2012. Upon closing of the transaction on December 31, 2014, E.ON retained a 20% interest and remained the operator.

Keechi Wind Project

In January 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. Keechi will deliver 100% of the electricity generated 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 to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, Enbridge is constructing and will own and operate the WRGGS to provide natural gas gathering services to the 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 and the Big Foot Pipeline portion is expected to be placed into service in the third 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., Enbridge is constructing a 64-kilometre (40-mile) 20-inch oil pipeline with capacity of 100,000 bpd from the Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil pipeline project is complementary to Enbridge’s undertaking of the WRGGS construction discussed above. Upon completion of the project, Enbridge will operate the Big Foot Pipeline, located approximately 274 kilometres (170 miles) south of the coast of Louisiana. The estimated capital cost of the project is approximately US$0.2 billion, with expenditures to date of approximately US$0.2 billion. As noted above, the Big Foot Pipeline is expected to enter service in the third quarter of 2015.

Aux Sable Extraction Plant Expansion

In October 2014, the Company approved the expansion of fractionation capacity and related facilities at its Aux Sable Extraction Plant located in Channahon, Illinois. The expansion will facilitate 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 be placed into service in 2016, with Enbridge’s share of the project cost being approximately US$0.1 billion.

Heidelberg Oil Pipeline

The Company will construct, own and operate a crude oil pipeline in the Gulf of Mexico to connect the proposed 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, will originate in Green Canyon Block 860, approximately 320 kilometres (200 miles) southwest of New Orleans, Louisiana and in an estimated 1,600 metres (5,300 feet) of water. Heidelberg Pipeline is expected to be operational in 2016 at an approximate cost of US$0.1 billion, with expenditures to date of approximately US$0.1 billion.

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, 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 (3,500 feet). After finalization of scope and a definitive cost estimate, Stampede Pipeline is now expected to be completed at an approximate cost of US$0.2 billion and is expected to be placed into service in 2018.

SPONSORED INVESTMENTS – ENBRIDGE ENERGY PARTNERS, L.P.

Line 6B 75-Mile Replacement Program

The Line 6B 75-Mile Replacement Program included the replacement of 120 kilometres (75 miles) of non-contiguous sections of Line 6B of EEP’s Lakehead System. The Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. The new segments were completed in components, with approximately 104 kilometres (65 miles) of segments placed in service in 2013. The two remaining 8-kilometre (5-mile) segments in Indiana were placed in service in March 2014. The total cost of the replacement program was approximately US$0.4 billion and EEP is recovering these costs through a tariff surcharge that is part of the system-wide rates for the Lakehead System.

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 being undertaken by EEP include an expansion of its Line 5 and expansions of the United States mainline involving the Spearhead North Pipeline (Line 62) and further segments of Line 6B. For discussion on Enbridge’s portion of Eastern Access, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Eastern Access.

In 2013, EEP completed and placed into service the expansion of its Line 5 light crude oil line between Superior, Wisconsin and the international border at the St. Clair River. The Line 5 expansion increased capacity by 50,000 bpd at an approximate cost of US$0.1 billion. Also in 2013, EEP completed and placed into service the expansion of Line 62 between Flanagan, Illinois and Griffith, Indiana, which increased capacity by 105,000 bpd.

EEP also replaced additional sections of Line 6B in Indiana and Michigan, which included the addition of new pumps and terminal upgrades at Hartsdale, Griffith and Stockbridge, as well as tanks at Flanagan, Stockbridge and Hartsdale, to increase capacity from 240,000 bpd to 500,000 bpd. Portions of the existing 30-inch diameter pipeline were also replaced with 36-inch diameter pipe. The Line 6B project is split into two phases. The segment between Griffith and Stockbridge was completed in May 2014 and the segment from Ortonville, Michigan to the international border at the St. Clair River was completed in September 2014. The replacement of the Line 6B sections is in addition to the Line 6B 75-mile Replacement Program discussed previously. Following detailed engineering estimates completed in the first quarter of 2014 which reflect issues with local ground terrain conditions including tie-ins, the expected cost of the United States mainline expansions is approximately US$2.4 billion and includes the US$0.1 billion cost of the previously discussed Line 5 expansion.

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 Griffith, Niles and Mendon stations, additional modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. Following the completion, in the first quarter of 2014, of a detailed engineering estimate and a scope revision that removed a proposed tank, the total cost of the project is approximately US$0.3 billion. The project is expected to be placed into service in early 2016.

The total estimated cost of the projects being undertaken by EEP as part of the Eastern Access initiative, including the United States mainline expansions, the Line 5 expansion and the Line 6B capacity expansion project, is approximately US$2.7 billion, with expenditures to date of approximately US$2.1 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%.

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 included increasing capacity from 450,000 bpd to 570,000 bpd at an estimated capital cost of approximately US$0.2 billion. The second phase of the expansion will increase capacity from 570,000 bpd to 800,000 bpd at an estimated capital cost of approximately US$0.2 billion. Both phases of the Alberta Clipper expansion require only the addition of pumping horsepower and no pipeline construction. Subject to regulatory and other 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, the initial phase was mechanically completed in the third quarter of 2014 and the second phase is expected to be in-service in 2015. It is anticipated that obtaining Federal regulatory approval will take longer than originally planned though approval is expected in the second half of 2015. A number of temporary system optimization actions are being undertaken to substantially mitigate any impact on throughput associated with the initial 120,000 bpd capacity increase.

In November 2014, several environmental and Native American groups filed a complaint in the United States District Court in Minnesota against the United States Department of State (DOS). The Complaint alleges, among other things, that the DOS is in violation of the NEPA by acquiescing in Enbridge’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 Enbridge’s application to the DOS to increase Alberta Clipper’s permitted cross border capacity is still pending. Enbridge has moved to intervene in the case and a decision at the trial level is not expected before the third quarter of 2015.

The current scope of the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois also consists of two phases. Both phases of the Southern Access expansion 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 also plans to undertake a further expansion of the Southern Access line between Superior and Flanagan to increase capacity from 560,000 bpd to 1,200,000 bpd and add crude oil tankage at new and existing sites. The pipeline expansion will be split into two tranches. The first tranche will expand the pipeline capacity to 800,000 bpd at an estimated capital cost of approximately US$0.4 billion and is expected to be in service in the second quarter of 2015. Additional tankage is expected to cost approximately US$0.4 billion and will be completed on various dates beginning in the second quarter of 2015 through early 2016. The second tranche, which remains subject to regulatory and other approvals, will expand the pipeline capacity to 1,200,000 bpd at an estimated capital cost of approximately US$0.4 billion. The Company is exploring with shippers the potential to delay the in-service date of the final tranche of the Line 61 expansion to align more closely with the currently anticipated in-service date for Sandpiper, which will drive the need for additional downstream capacity on the Lakehead System.

As part of the Light Oil Market Access Program, EEP also plans to expand the capacity of the Lakehead System between Flanagan, Illinois and Griffith, Indiana. This section of the Lakehead System will be expanded by constructing a 127-kilometre (79-mile), 36-inch diameter twin of the existing Spearhead North Pipeline (Line 62). The project is expected to be completed at an estimated cost of approximately US$0.5 billion. Subject to regulatory and other approvals, the new line will have an initial capacity of 570,000 bpd and is expected to be placed into service in the third quarter of 2015.

The projects collectively referred to as the Lakehead System Mainline Expansion are expected to cost approximately US$2.3 billion, with expenditures incurred to date of approximately US$1.1 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. 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%.

Beckville Cryogenic Processing Facility

EEP and its partially-owned subsidiary, MEP, are constructing a cryogenic natural gas processing plant near Beckville (the Beckville Plant) in Panola County, Texas. The Beckville Plant will offer 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 planned natural gas processing capability of 150 mmcf/d and is also expected to produce 8,500 bpd of NGL. The Beckville Plant is now expected to be placed into service in the second quarter of 2015 at an estimated cost of approximately US$0.1 billion. Expenditures incurred to date are approximately US$0.1 billion.

Eaglebine Gathering

In February 2015, EEP and MEP announced they are entering into the emerging Eaglebine shale play in East Texas through two transactions totalling approximately US$0.2 billion. EEP and MEP have commenced construction of a lateral and associated facilities that will 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 are projected to be placed into service by late 2015, with the lateral expected to be in service by mid-2016. MEP also executed an agreement with New Gulf Resources, LLC (NGR) to purchase NGR’s midstream business in Leon, Madison and Grimes Counties, Texas. The acquisition consists of a natural gas gathering system that is currently in operation.

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. Sandpiper is expected to cost approximately US$2.6 billion, with expenditures incurred to date of approximately US$0.4 billion.

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, targeted for 2017 due to a longer than expected permitting process in the State of Minnesota.

A petition was filed with the Federal Energy Regulatory Commission (FERC) to approve recovery of Sandpiper’s costs through a surcharge to the NDPC rates between Beaver Lodge and Clearbrook and a cost of service structure for rates between Clearbrook and Superior. In March 2013, the FERC denied the petition on procedural grounds. In late 2013, EEP held an open season to solicit commitments from shippers for capacity created by Sandpiper. The open season closed in late January 2014 with the receipt of a further capacity commitment which can be accommodated within the planned incremental capacity identified above. EEP re-filed its petition with the FERC on February 12, 2014 and received a FERC declaratory order in May 2014 approving the tariffs structure for the project. The pipeline is now expected to begin service in 2017, subject to obtaining regulatory and other approvals.

United States Line 3 Replacement Program

In March 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. EEP will undertake the United States portion of the Line 3 Replacement 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. The L3R Program is expected to achieve an equivalent 34-inch diameter pipeline capacity of approximately 760,000 bpd, which will enhance the flexibility and reliability of the Enbridge mainline system’s overall western Canada export capacity.

Subject to regulatory and other approvals, the U.S. L3R Program is targeted to be completed in late 2017 at an estimated capital cost of approximately US$2.6 billion, with expenditures to date of approximately US$0.2 billion. 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.

GROWTH PROJECTS – OTHER PROJECTS UNDER DEVELOPMENT

The following projects have been announced by the Company, but have not yet met Enbridge’s criteria to be classified as commercially secured. The Company also has significant 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 1,177-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.

On December 19, 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 JRP recommended to the Governor in Council that Certificates of Public Convenience and Necessity (Certificates) for the oil and condensate pipelines, incorporating the terms and conditions in their report, be issued to Northern Gateway pursuant to Part III of the NEB Act. 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 for the pipelines.

On June 17, 2014, the Governor in Council issued an Order in Council approving the JRP recommendation, including all 209 recommended conditions. The NEB issued the Certificates for the oil and condensate pipelines on June 18, 2014.

Nine applications for leave for judicial review of the Order in Council have been filed pursuant to section 55 of the NEB Act. The applicants make two basic arguments in seeking leave. First, they argue that the report and the Order in Council contain evidentiary gaps or gaps in reasoning. Second, they allege that the Crown has failed to discharge its constitutional duty to consult and, if appropriate, accommodate the Aboriginal applicants.

On September 26, 2014, the Federal Court of Appeal (Federal Court) granted leave to all nine applications and on December 17, 2014, the Federal Court issued a decision accepting the request by all parties to consolidate the nine applications into a single proceeding (the Application) and stated that delays in the hearing of the Application should be minimized. The Federal Court then set a schedule which would culminate with the filing of the Appellants’ Memoranda of Fact and Law by May 22, 2015 and the Respondents’ Memoranda by June 5, 2015. Based on this schedule, Northern Gateway expects that the hearing on the Application will occur in the fall of 2015. Depending on the outcome of these proceedings, which is anticipated for late 2015, an application for Leave to Appeal to the Supreme Court of Canada is a possibility.

In October 2014, 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.

Subject to continued commercial support, receipt of regulatory and other approvals and adequately addressing landowner and local community concerns (including those of Aboriginal communities), the Company now estimates that Northern Gateway could be in service in 2019 at the earliest. The timing and outcome of judicial reviews could also impact the start of construction or other project activities, which may lead to a delay in the start of operations beyond the current forecast. Of the 45 Aboriginal groups eligible to participate as equity owners, 26 have signed up to do so.

Expenditures to date, which relate primarily to the regulatory process, are approximately $0.5 billion, of which approximately half is being funded by potential shippers on Northern Gateway. 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 the terms of its continued participation in the project.

LIQUIDS PIPELINES

EARNINGS

	2014	2013	2012

(millions of Canadian dollars)
Canadian Mainline	500	460	432
Regional Oil Sands System	181	170	110
Seaway and Flanagan South Pipelines	74	48	24
Southern Lights Pipeline	49	49	42
Spearhead Pipeline	31	31	37
Feeder Pipelines and Other	23	12	10
Adjusted earnings	858	770	655
Canadian Mainline - changes in unrealized derivative fair value gains/(loss)	(370)	(268)	42
Canadian Mainline - Line 9B costs incurred during reversal	(8)	-	-
Canadian Mainline - Line 9 tolling adjustment	-	-	6
Regional Oil Sands System - make-up rights adjustment	6	(13)	-
Regional Oil Sands System - leak remediation and long-term pipeline stabilization costs	(4)	(56)	-
Regional Oil Sands System - leak insurance recoveries	8	-	-
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	-
Regional Oil Sands System - prior period adjustment	-	-	(6)
Seaway and Flanagan South Pipelines - make-up rights adjustment	(25)	-	-
Spearhead Pipeline - changes in unrealized derivative fair value gains	1	-	-
Feeder Pipelines and Other - make-up rights adjustment	3	-	-
Feeder Pipelines and Other - project development costs	(6)	-	-
Earnings attributable to common shareholders	463	427	697

Liquids Pipelines adjusted earnings were $858 million in 2014 compared with adjusted earnings of $770 million in 2013 and $655 million in 2012. The Company continued to realize growth on Canadian Mainline primarily from higher throughput from growing crude oil supply in western Canada and higher 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 International Joint Tariff (IJT) Residual Benchmark Toll. New assets placed into service in Regional Oil Sands System and the completion of Flanagan South and Seaway Pipeline Twin also contributed to adjusted earnings growth.

Liquids Pipelines earnings were impacted by the following adjusting items:

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

· Canadian Mainline earnings for 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 earnings for 2012 included a Line 9 tolling adjustment related to services provided in prior periods.

· Regional Oil Sands System earnings for 2014 and 2013 included make-up rights adjustments to recognize revenue for certain long-term take-or-pay contracts ratably 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 ratably 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 ratably over the life of the contract, consistent with contractual cash payments under the contract.

· Regional Oil Sands System earnings for 2014 and 2013 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 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.

· Regional Oil Sands System earnings for 2012 included a revenue recognition adjustment related to prior periods.

· Seaway and Flanagan South Pipelines earnings for 2014 included a make-up rights adjustment.

· Spearhead Pipeline earnings for 2014 included an unrealized fair value gain on derivative financial instruments.

· Feeder Pipelines and Other earnings for 2014 included a make-up rights adjustment.

· Feeder Pipelines and Other earnings for 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 Canadian Mainline and the Lakehead System (the portion of the mainline in the United States that is managed by Enbridge through its subsidiaries). Enbridge has operated, and frequently expanded, the mainline system since 1949. Through six adjacent pipelines, with a combined design operating capacity of approximately 2.6 million bpd, which cross the Canada/United States border near Gretna, Manitoba and Neche, North Dakota, the system transports various grades of crude oil and diluted bitumen from western Canada to the midwest region of the United States and eastern Canada. Also included in Canadian Mainline are two crude oil pipelines and one refined products pipeline located in eastern Canada.

Competitive Toll Settlement

Canadian Mainline tolls are governed by the 10-year settlement reached between Enbridge and shippers on its mainline system and approved by the NEB in 2011. The CTS, which took effect on July 1, 2011, covers local tolls to be charged for service on the mainline system (with the exception of Lines 8 and 9). Under the terms of the CTS, the initial Canadian Local Toll (CLT), applicable to deliveries within western Canada, was based on the 2011 Incentive Tolling Settlement (ITS) toll, subsequently adjusted by 75% of the Canada Gross Domestic Product at Market Price Index on July 1 of each year.

The CTS also provides for an IJT for crude oil shipments originating in Canada on the mainline system and delivered in the United States off the Lakehead System and into eastern Canada. The IJT, which is based on a fixed toll for the term of the settlement that was negotiated between Enbridge and shippers, will be adjusted annually by the same factor as the CLT.

In limited circumstances, the shippers or Enbridge may elect to renegotiate the toll. For shippers, the renegotiation rights exist in circumstances where Enbridge is seeking to recover from shippers, through tolls, potential increases to its cost structures. If a renegotiation of the toll 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.

Local tolls for service on the Lakehead System will not be affected by the CTS and will continue to be established pursuant to EEP’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.

The IJT is designed to provide mainline shippers with a stable and competitive long-term toll, preserving and enhancing throughput on both the Canadian Mainline and Lakehead System. Earnings under the CTS are subject to variability in volume throughput, as well as capital and operating costs and the United States dollar exchange rate. The Company may utilize derivative financial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues and commodity price risk resulting from exposure to crude oil and power prices.

Results of Operations

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 was a lower year-over-year average Canadian Mainline IJT Residual Benchmark Toll, with its impact especially prominent in the fourth quarter of 2014. Changes in the Canadian Mainline IJT Residual Benchmark Toll are inversely related to the Lakehead System Toll which, on average, was higher throughout 2014 due to the recovery of incremental costs associated with EEP’s growth projects. 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 continued to be impacted by the absence of revenues from Line 9B, which was idled in late 2013 and is being reversed and expanded as part of the Company’s Eastern Access initiative. For further information on Line 9B, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Eastern Access.

Canadian Mainline adjusted earnings for the year ended December 31, 2013 were $460 million compared with $432 million for the year ended December 31, 2012. The adjusted earnings increase was primarily driven by higher throughput from steady production from the oil sands in Alberta priced at levels that displaced other non-Canadian production from the midwest market and drove increased long-haul barrels on Canadian Mainline. Further volume growth on Canadian Mainline was limited towards the latter half of 2013 due to longer than expected refinery shutdowns and the delay in the start-up of a refinery conversion to heavy oil to the second quarter of 2014.

Partially offsetting the effect of increased throughput in 2013 was a lower Canadian Mainline IJT Residual Benchmark Toll effective April 1, 2013 compared with the corresponding 2012 period. Also negatively impacting 2013 adjusted earnings was an increase in power costs due to higher throughput, as well as higher depreciation and interest expense. Finally, income tax expense, which reflected current income taxes only, was lower due to higher available tax deductions from a larger asset base, including software.

Supplemental information on Canadian Mainline adjusted earnings for the years ended December 31, 2014, 2013 and 2012 is provided below.

Year ended December 31,	2014		2013		2012
(millions of Canadian dollars)
Revenues	1,465		1,434		1,367
Expenses
Operating and administrative	381		407		382
Power	160		122		112
Depreciation and amortization	270		244		219
	811		773		713
	654		661		654
Other income/(expense)	11		3		(4	)
Interest expense	(162	)	(162	)	(131	)
	503		502		519
Income taxes	(3	)	(42	)	(87	)
Adjusted earnings	500		460		432

Effective United States to Canadian dollar exchange rate1	1.016		0.999		0.971

December 31,	2014		2013		2012
(United States dollars per barrel)
IJT Benchmark Toll2	$4.02		$3.98		$3.94
Lakehead System Local Toll3	$2.49		$2.18		$1.85
Canadian Mainline IJT Residual Benchmark Toll4	$1.53		$1.80		$2.09

1 Inclusive of realized gains and losses on foreign exchange derivative financial instruments.

2 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.

3 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. 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 FERC on June 27, 2014, and, effective August 1, 2014, the Lakehead System Local Toll increased from US$2.17 to US$2.49 per barrel.

4 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.

Throughput Volume1

	Q1	Q2	Q3	Q4	Full Year
2014	1,904	1,968	2,039	2,066	1,995
2013	1,783	1,604	1,736	1,827	1,737
2012	1,687	1,659	1,617	1,622	1,646

1 Throughput, presented in thousands of barrels per day, represents mainline deliveries ex-Gretna, Manitoba, which is made up of United States and eastern Canada deliveries entering the mainline in western Canada.

Canadian Mainline revenues include the portion of the system covered by the CTS as well as revenues from Lines 8 and 9 in eastern Canada. Lines 8 and 9 are currently tolled on a separate basis and comprise a relatively small proportion of total Canadian Mainline revenues. Line 9B was idled in late 2013 and is being reversed and expanded as part of the Company’s Eastern Access initiative. 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 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. The primary drivers of future increases in operating costs are expected to be normal escalation in wage rates, prices for purchased services, the addition of new facilities and more extensive integrity, ORM and maintenance programs.

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.

The preceding financial overview includes expectations regarding future events and operating conditions that the Company believes are reasonable based on currently available information; however, such statements are not guarantees of future performance and are subject to change.

REGIONAL OIL SANDS SYSTEM

Regional Oil Sands System includes two long haul pipelines, the Athabasca Pipeline and the Waupisoo 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. The Regional Oil Sands System also includes the Wood Buffalo Pipeline, Woodland Pipeline and Norealis Pipeline which provide access for oil sands production from near Fort McMurray to the Cheecham Terminal as well as variety of other facilities such as the MacKay River, Christina Lake, Surmont and Long Lake laterals and related facilities.

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 a pipeline hub at Hardisty, Alberta. The Athabasca Pipeline’s capacity is 570,000 bpd, depending on the viscosity of crude being shipped, after completion of a pipeline expansion in December 2013. The Company has a long-term (30-year) take-or-pay contract with a major shipper on the Athabasca Pipeline that commenced in 1999. Revenues are recorded based on the contract terms negotiated with the major shipper, 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 initiates at Enbridge’s Cheecham Terminal and terminates at its Edmonton Mainline Terminal. The pipeline has a capacity of 415,000 bpd, depending on crude slate, and can ultimately be expanded to 600,000 bpd. Enbridge has a long-term (25-year) take-or-pay commitment with multiple shippers on the Waupisoo Pipeline who collectively have contracted for approximately three-quarters of the capacity.

Prior to December 10, 2012, Regional Oil Sands System included the Hardisty Storage Caverns which included four salt caverns totalling 3.5 million barrels of storage capacity. The capacity at the facilities is fully subscribed under long-term contracts that generate revenues from storage and terminalling fees. Along with the Hardisty Contract Terminals, the Hardisty Storage Caverns were transferred to the Fund in December 2012. Refer to Sponsored Investments – Enbridge Income Fund – Enbridge Income Fund Drop Down Transactions for details of the transfer.

Results of Operations

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 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.

Adjusted earnings for the year ended December 31, 2013 were $170 million compared with $110 million for the year ended December 31, 2012. The increase in adjusted earnings was due to higher contracted volumes on the Athabasca Pipeline, higher capital expansion fees on the Waupisoo Pipeline and earnings from new assets placed into service in late 2012, including the Woodland and Wood Buffalo pipelines. Partially offsetting these earnings increases were higher operating and administrative costs, higher depreciation expense due to the commissioning of new assets and the absence of Hardisty Caverns earnings following the sale to the Fund in the fourth quarter of 2012.

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, 2014 and 2013, the Company’s earnings reflected remediation and long-term stabilization costs of approximately $4 million and $56 million after-tax and before insurance recoveries. 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. 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. The cost estimates exclude any potential fines or penalties resulting from the ongoing investigation from a provincial governmental agency.

SEAWAY AND FLANAGAN SOUTH PIPELINES

Seaway and Flanagan South Pipelines include Enbridge’s 50% interest in Seaway Pipeline and whole ownership of the recently completed 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 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, 2014 were $74 million compared with 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 earnings for the year ended December 31, 2013 were $48 million compared with earnings of $24 million for the year ended December 31, 2012. The higher contribution reflected a full year of operations and incremental available capacity on the pipeline in 2013 as noted above. Despite the increased capacity, actual throughput experienced in 2013 was curtailed due to constraints on third party takeaway facilities and during the latter part of the year due to loss of spot volume shipments as a result of a lower spread between crude oil prices at Cushing, Oklahoma and the Gulf Coast. Partially offsetting the earnings increase was higher financing costs and higher depreciation expense from an increased asset base.

Seaway Pipeline Regulatory Matter

Seaway Pipeline filed an application for market-based rates in December 2011. Initially, the FERC rejected the application in March 2012 and Seaway Pipeline appealed to the District of Columbia Circuit. In response, the FERC set the application for further proceedings and the appeal was stayed. Since the FERC had not issued a ruling on this 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. During the evidentiary stage, FERC staff filed evidence stating that the committed and uncommitted rates are subject to review and adjustment. Seaway Pipeline filed a Petition for Declaratory Order (PDO) requesting the FERC confirm that it will honour and uphold existing contracts. The FERC issued a decision denying the PDO on procedural grounds but stated that it will uphold its longstanding policy of honouring contracts.

The FERC hearings concluded with all parties filing their respective briefs. In September 2013, a decision from the Administrative Law Judge (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 is still pending.

In relation to the original market based rate application, the FERC issued its decision rejecting Seaway Pipeline’s application for market based rates in February 2014 and 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. No procedural schedule has been set.

SOUTHERN LIGHTS PIPELINE

The 180,000 bpd, 20-inch diameter Southern Lights Pipeline was placed into service on July 1, 2010, transporting diluent from Chicago, Illinois to Edmonton, Alberta. Enbridge receives tariff revenues under long-term contracts with committed shippers. Tariffs provide for recovery of all operating and debt financing costs plus a ROE of 10%. Uncommitted volumes, up to a specified amount, generate tariff revenues that are fully credited to all shippers. Enbridge retains 25% of uncommitted tariff revenues on volumes above the specified amount, with the remainder being credited to shippers. As part of Enbridge’s sponsored vehicle strategy, in November 2014, the Fund subscribed for and purchased 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, provide a defined cash flow stream to the Fund and a related financing cost to Southern Lights Pipeline. Refer to Sponsored Investments – Enbridge Income Fund – Enbridge Income Fund Drop Down Transactions.

Results of Operations

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.

Southern Lights Pipeline earnings for the year ended December 31, 2013 were $49 million compared with $42 million for the year ended December 31, 2012. The increase in earnings reflected higher recovery of negotiated depreciation rates in 2013 transportation tolls.

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. 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 $31 million for each of the years ended December 31, 2014 and 2013, respectively. 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.

Adjusted earnings for Spearhead Pipeline were $31 million for the year ended December 31, 2013 compared with $37 million for the year ended December 31, 2012. Higher contributions from increased throughput due to higher demand at Cushing, Oklahoma for further transportation on Seaway Pipeline to the Gulf Coast refining market were more than offset by higher operating expense, predominantly higher pipeline integrity expenditures. Operating margins were also compressed in 2013 due to an increase in power costs that resulted from transporting a mix of heavier crude.

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 business development costs related to Liquids Pipelines activities.

Prior to December 10, 2012, Feeder Pipelines and Other also included the Hardisty Contract Terminals, which is comprised of 19 tanks with a working capacity of approximately 7.5 million barrels of storage capacity. Along with the Hardisty Storage Caverns, the Hardisty Contract Terminals were transferred to the Fund in December 2012. Refer to Sponsored Investments – Enbridge Income Fund – Enbridge Income Fund Drop Down Transactions for details of the transfer.

Results of Operations

Feeder Pipelines and Other adjusted earnings were $23 million 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.

Feeder Pipelines and Other adjusted earnings were $12 million for the year ended December 31, 2013 compared with $10 million for the year ended December 31, 2012. The earnings increase was primarily attributable to higher volumes and 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 reduce capacity bottlenecks and enhance access to markets for customers. Liquids Pipelines 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. Expected to be completed in late 2017, this project will not increase the overall capacity of the mainline system, but will instead 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

Regulatory scrutiny over the integrity of Liquids Pipelines 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 constructions 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 segment’s 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 best 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

	2014	2013		2012
(millions of Canadian dollars)
Enbridge Gas Distribution Inc. (EGD)	158	156		149
Other Gas Distribution and Storage	19	20		27
Adjusted earnings	177	176		176
EGD - (warmer)/colder than normal weather	36	9		(23	)
EGD - gas transportation costs out-of-period adjustment	-	(56	)	-
EGD - tax rate changes	-	-		(9	)
EGD - recognition of regulatory asset	-	-		63
Earnings attributable to common shareholders	213	129		207

Adjusted earnings from Gas Distribution were $177 million for the year ended December 31, 2014 compared with $176 million for each of the years ended December 31, 2013 and 2012. EGD 2014 results reflect the approval of its five-year customized IR Plan by the OEB. EGD adjusted earnings increased slightly due to customer growth and lower depreciation expense under a new approach for determining depreciation and future removal and site restoration reserves. Partially offsetting these positive factors were lower rates and the resumption of the earnings sharing mechanism.

Gas Distribution earnings were impacted by the following adjusting items:

· EGD earnings for each period were adjusted to reflect the impact of weather.

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

· EGD earnings for 2012 reflected the impact of unfavourable tax rate changes on deferred income tax liabilities.

· EGD earnings for 2012 included the recognition of a regulatory asset related to recovery of other postretirement benefit obligations (OPEB) costs pursuant to an OEB rate order. Refer to Gas Distribution – Enbridge Gas Distribution Inc. – Incentive Rate Plan.

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

In July 2013, EGD filed an application with the OEB for the setting of rates through a customized IR Plan for the period of 2014 through to 2018. EGD continued to apply 2013 rates in 2014, pursuant to a November 2013 interim rate order, until a final rate order for 2014 rates was issued by the OEB. A decision from the OEB was provided on July 17, 2014, with a subsequent decision and rate order provided on August 22, 2014. The OEB approved the customized IR Plan, 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 OEB’s decision provides the methodology for establishing rates for the distribution of natural gas for a five-year period from 2014 through 2018. The customized IR Plan provides EGD the framework needed for anticipated investment in its Ontario natural gas distribution system and incentivizes the Company to implement productivity efficiencies that benefit customers.

The OEB approved final 2014 rates to be implemented with the October 2014 Quarterly Rate Adjustment Mechanism, with an effective date of January 1, 2014. 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 annual updates reduce forecast risk and ensure rates reflect current market conditions. 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.

In order to align the interest of customers with the Company’s shareholders, an earnings sharing mechanism was included as part of the customized IR Plan, 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 year ended December 31, 2014, EGD recognized $12 million 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 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.

Prior to 2013, EGD operated under a five-year revenue cap IR mechanism, with rates calculated using a formula approved by the OEB based on revenue per customer. Under this mechanism, the Company was allowed to earn and fully retain 100 basis points (bps) over the base return. Any return over 100 bps was required to be shared with customers on an equal basis. For the year ended December 31, 2012, EGD recognized $10 million as a return of revenues to customers in relation to the earnings sharing mechanism.

Results of Operations

EGD adjusted earnings for the year ended December 31, 2014 were $158 million compared with $156 million for the year ended December 31, 2013. EGD adjusted earnings reflected the impact of the OEB decision on EGD’s customized IR Plan which was approved with modifications by the OEB in July 2014. EGD operated the first half of 2014 under OEB approved interim distribution rates. On August 22, 2014, an OEB Rate Order under the customized IR Plan approved the final rates with an effective date of January 1, 2014.

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 approved 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.

EGD adjusted earnings for the year ended December 31, 2013 were $156 million compared with $149 million for the year ended December 31, 2012. Higher adjusted earnings reflected customer growth, the absence of the earnings sharing under the 2013 Settlement and higher shared savings mechanism revenues, which resulted from exceeding targets on delivery of energy efficiency programs. Also favourably impacting adjusted earnings was the recovery of pension costs allowed to be passed on to customers under the 2013 Settlement, whereas previously these costs were partially disallowed under the 2012 IR mechanism. Partially offsetting the favourable adjusted earnings increase was lower revenues from non-regulated operations.

OTHER GAS DISTRIBUTION AND STORAGE

Other Gas Distribution includes natural gas distribution utility operations in Quebec and New Brunswick, the most significant being Enbridge Gas New Brunswick Inc. (EGNB) which is wholly-owned and operated by the Company. EGNB owns the natural gas distribution franchise in the province of New Brunswick and has approximately 11,000 customers and is regulated by the New Brunswick Energy and Utilities Board (EUB).

Results of Operations

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 a contract, which expired in October 2014, 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. Higher distribution volumes and higher rates that became effective in May 2014 partially offset the decreased earnings in EGNB.

Other Gas Distribution and Storage earnings were $20 million for the year ended December 31, 2013 compared with $27 million for the year ended December 31, 2012. The decrease in earnings reflected lower rates from a revised rate setting methodology that became effective October 1, 2012 in EGNB. The earnings decrease was partially offset by new rates that became effective August 1, 2013 which allowed EGNB to fully recover its revenue requirement and drove higher earnings in the second half of 2013.

Enbridge Gas New Brunswick Inc. – Regulatory Matters

On December 9, 2011, the Government of New Brunswick tabled and then subsequently passed legislation related to the regulatory process for setting rates for gas distribution within the province. The legislation permitted the government to implement new regulations that could affect the franchise agreement between EGNB and the province, impact prior decisions by the province’s independent regulator and influence the regulator’s future decisions.

A final rates and tariffs regulation was subsequently enacted by the Government of New Brunswick on April 16, 2012. Based on the amended rate setting methodology and specific conditions outlined therein, EGNB no longer met the criteria for the continuation of rate-regulated accounting. As a result, the Company eliminated from its Consolidated Statements of Financial Position a deferred regulatory asset of $180 million and a regulatory asset with respect to capitalized operating costs of $103 million, net of an income tax recovery of $21 million. As the final rates and tariffs regulation published on April 16, 2012 provided further evidence of a condition that existed on December 31, 2011, the charge totalling $262 million, after-tax, was reflected as a subsequent event in the Company’s Consolidated Financial Statements for the year ended December 31, 2011 presented in accordance with U.S. GAAP and filed in May 2012.

The Company commenced legal proceedings against the Government of New Brunswick, seeking damages for breach of contract, in April 2012. The Company also commenced a separate application to the New Brunswick Court of Queen’s Bench to quash the Government’s rates and tariffs regulation in May 2012. The Company’s application was initially dismissed, but on appeal it was ultimately successful, in part. The Court of Appeal ruled that the part of the rates and tariffs regulation that caps rates according to a maximum revenue-to-cost ratio was beyond the regulation-making authority of the New Brunswick Lieutenant Governor-in-Council. The Court of Appeal upheld the portion of the regulation that requires EGNB to charge customers the lower of market or cost-based rates. As a result of this outcome, EGNB applied on June 14, 2013 to the EUB for new rates, effective July 1, 2013, for commercial and industrial customers. On July 26, 2013, the EUB granted EGNB’s application for new rates, but with an effective date of August 1, 2013. The EUB’s decision enabled EGNB to fully recover its revenue requirement from August 1, 2013 until the next rate period. EGNB’s 2014 rate application was approved in April 2014 by the EUB and its application for 2015 rates was approved in December 2014.

On February 4, 2014, EGNB commenced a further legal proceeding against the Government of New Brunswick. The action seeks damages for improper extinguishment of the deferred regulatory asset that was previously eliminated from EGNB’s Consolidated Statements of Financial Position, as discussed above.

There is no assurance that any of EGNB’s legal proceedings 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 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 charged to customers could negatively impact earnings.

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

	2014		2013		2012
(millions of Canadian dollars)
Aux Sable	28		49		68
Energy Services	35		75		40
Alliance Pipeline US	41		43		39
Vector Pipeline	15		22		22
Canadian Midstream	23		12		-
Enbridge Offshore Pipelines (Offshore)	(2	)	(2	)	(3	)
Other	(4	)	4		10
Adjusted earnings	136		203		176
Aux Sable - changes in unrealized derivative fair value gains	-		-		10
Energy Services - changes in unrealized derivative fair value gains/(loss)	424		(206	)	(537	)
Offshore - gain on sale of non-core assets	57		-		-
Offshore - asset impairment loss	-		-		(105	)
Other - changes in unrealized derivative fair value loss	-		(61	)	-
Earnings/(loss) attributable to common shareholders	617		(64	)	(456	)

Adjusted earnings from Gas Pipelines, Processing and Energy Services were $136 million for the year ended December 31, 2014 compared with $203 million for the year ended December 31, 2013 and $176 million for the year ended December 31, 2012. Unfavourable market conditions in Aux Sable and Energy Services contributed to lower adjusted earnings in 2014. Lower fractionation margins and lower volumes at upstream processing plants contributed to lower Aux Sable earnings over the past two years. In Energy Services, narrowing location spreads and less favourable conditions in certain markets accessed by committed transportation capacity, combined with associated unrecovered demand charges, drove lower adjusted earnings after a very strong 2013 fiscal year. Partially offsetting the decrease were positive contributions from the Company’s Canadian midstream assets and new renewable energy investments.

Gas Pipelines, Processing and Energy Services earnings/(loss) were impacted by the following adjusting items:

· Aux Sable earnings for 2012 period reflected changes in the fair value of unrealized derivative financial instruments related to the Company’s forward gas processing risk management position.

· 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 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.

· Offshore earnings for 2014 included a gain from the disposal of non-core assets.

· Offshore loss for 2012 was impacted by an asset impairment loss related to certain of its assets, predominantly located within the Stingray and Garden Banks corridors. Refer to Gas Pipelines, Processing and Energy Services – Enbridge Offshore Pipelines – Asset Impairment.

· 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.

AUX SABLE

Enbridge owns a 42.7% interest in Aux Sable US and a 50% interest in Aux Sable Canada (together, Aux Sable). Aux Sable US owns and operates a NGL extraction and fractionation plant outside Chicago, Illinois 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, maintenance and capital costs associated with its facilities subject to certain limits on capital costs. 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 and operates 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 by Aux Sable US and the Septimus Gas Plant and the Septimus Pipeline in the Montney area of British Columbia, owned by Aux Sable Canada.

Aux Sable Canada has contracted capacity of the Septimus Pipeline and the Septimus Gas Plant 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 2014, the majority of capacity at the Palermo Gas Plant and 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 received a Notice of Violation (NOV) 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 NOV, Aux Sable discovered what it believes to be additional exceedance of currently permitted limits for Volatile Organic Material. Aux Sable is engaged in discussions with the EPA to evaluate the potential impact and ultimate resolution of these issues. At this time, the Company is unable to reasonably estimate the financial impact, if any, which might result from discussions with the EPA.

Results of Operations

Aux Sable earnings for the year ended December 31, 2014 were $28 million compared with $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 adjusted earnings for the year ended December 31, 2013 were $49 million compared with adjusted earnings of $68 million for the year ended December 31, 2012. The decrease in adjusted earnings was mainly attributable to lower fractionation margins and lower ethane processing volumes due to ethane rejections. Lower fractionation margins resulted in a decrease in contributions from the upside sharing mechanism in Aux Sable’s production sales agreement compared with the prior year.

Aux Sable Feedstock Supply

Aux Sable extracts and sells NGL from natural gas shipped on Alliance Pipeline under current long-term transportation contracts and also secures NGL feedstock for its Channahon plant through rich-gas premium contracts with producers. Commencing December 1, 2015, when gas transportation services under Alliance Pipeline’s proposed new service offerings are scheduled to start, Aux Sable has contracted for additional liquids-rich gas supplies with producers. Aux Sable producers have entered into a variety of precedent transportation agreements with Alliance Pipeline for its new transportation services. Aux Sable has entered into certain gas purchase and sales contracts with several counterparties at Alliance Pipeline’s proposed Alberta Transfer Point. Any commodity price exposure created from Aux Sable’s gas purchase and resale business is closely monitored and must comply with its formal risk management policies that are consistent with the Company’s risk management practices. For further details on Alliance Pipeline Recontracting, refer to Sponsored Investments – Enbridge Income Fund – 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 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 margins achieved from the sale of extracted NGL after the fractionation process. 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 the margin earned through the upside sharing mechanism. Alliance Pipeline is well-positioned to deliver incremental liquids-rich gas production from new developments in the Montney, Duvernay and Bakken regions, thereby mitigating volume risk. In addition, Aux Sable attracts liquids-rich gas to Alliance Pipeline through inducement and rich-gas premium contracts with producers.

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 $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 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. Energy Services adjusted earnings are dependent on market conditions and results achieved in one period may not be indicative of results achieved in future periods.

Energy Services adjusted earnings were $75 million for the year ended December 31, 2013 compared with $40 million for the year ended December 31, 2012. The increase in adjusted earnings reflected wide location and crude grade differentials which gave rise to a greater number of and more profitable margin opportunities during the first half of 2013. These physical marketing opportunities began to diminish in the third quarter and culminated in a fourth quarter adjusted loss for Energy Services. Market conditions contributing to the fourth quarter adjusted loss included physical constraints which limited physical movement of barrels, such as pipeline apportionment and refinery outages, narrowing location spreads among markets physically accessed by Tidal Energy’s committed transportation capacity and narrowing grade differentials which limited tank management opportunities. Although profitability declined in most lines of business, the loss in the fourth quarter of 2013 primarily related to losses realized on financial contracts intended to hedge the value of committed physical transportation capacity, but which were not effective in doing so in the last three months of the year.

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. To the extent a forecasted transaction does not occur as anticipated, hedge ineffectiveness or termination may result. Certain financial contracts may not qualify for cash flow hedge accounting; therefore, the Company’s earnings are exposed to associated changes in the mark-to-market value of these contracts.

Competition

Energy Services earnings are generated from arbitrage opportunities which, by their nature, can be replicated by other competitors. An increase in market participants looking for similar arbitrage opportunities 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

Alliance Pipeline, which includes both the Canadian (Alliance Pipeline Canada) and United States (Alliance Pipeline US) portions of the pipeline system, 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 Channahon, Illinois. Alliance Pipeline US and Alliance Pipeline Canada have firm service shipping contract capacity to deliver 1.466 billion cubic feet per day (bcf/d) and 1.325 bcf/d, respectively. Alliance Pipeline connects with the Aux Sable NGL extraction and fractionation plant. 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 natural gas markets in the midwestern and eastern United States and eastern Canada. In September 2013, Alliance US completed construction of the Tioga Lateral Pipeline (Tioga Lateral) which facilitates delivery of natural gas from the Tioga field processing plant in the Bakken to downstream markets.

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

Results of Operations

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 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 which was placed into service in September 2013.

Alliance Pipeline US earnings were $43 million for the year ended December 31, 2013 compared with earnings of $39 million for the year ended December 31, 2012. The increase in earnings in 2013 compared with 2012 reflected an increase in depreciation expense recovered through tolls and earnings related to the Tioga Lateral.

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 and the Northern Border Pipeline in Joliet, Illinois. Vector has the capacity to deliver a nominal 1.3 bcf/d and is operating at or near capacity. The Company provides operating services to and holds a 60% joint venture interest in Vector.

Results of Operations

Vector earnings were $15 million for the year ended December 31, 2014 compared with earnings of $22 million for the years ended December 31, 2013 and 2012. The year-over-year decrease in Vector earnings reflected lower depreciation expense recognized in tolls, partially offset by increased demand for natural gas due to abnormal winter weather conditions experienced in the first quarter of 2014.

Transportation Contracts

The total long haul capacity of Vector is approximately 94% committed through November 2015. Approximately 55% of the long haul capacity is committed through firm negotiated rate transportation contracts with shippers and approved by the FERC, while the remaining committed capacity is sold at market rates.

In December 2014, shippers under negotiated rate transportation contracts which represent 20% of the system’s long haul capacity elected to extend their commitments through December 1, 2017 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.

Vector has recently 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.

Transportation service is provided through a number of different forms of service agreements, such as Firm Transportation Service and Interruptible Transportation 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 2014, 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 2014, 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 – Enbridge Income Fund – Business Risks – Alliance Pipeline.

Asset Utilization

Currently, natural gas pipeline capacity out of the WCSB exceeds supply, due to the low price of natural gas and increased production from new shale gas developments. Vector has been minimally impacted by this excess supply environment to date mainly because of long-term capacity contracts extending primarily to November 2015. However, excess supply and depressed natural gas prices could lead to a reduction or deferral of investment in upstream gas development and could negatively impact re-contracting beyond this term until further development of Marcellus/Utica sourced gas. Vector has entered into precedent agreements to provide transport service to two proposed greenfield pipeline projects that will extend back to the Marcellus/Utica supply basin. These arrangements, scheduled to commence in 2017, will effectively fill all available capacity from current contract roll-offs scheduled through 2019.

Competition

Vector faces competition for pipeline transportation services to its delivery points from new supply sources and traditional low cost pipelines, which could offer transportation that is more desirable to shippers because of cost, supply location, facilities or other factors. Vector has mitigated this risk by entering into long-term firm transportation contracts and the effectiveness of these contracts is evidenced by the increased utilization of the pipeline since its construction, despite the presence of transportation alternatives.

Vector also faces potential competition from new sources of natural gas, such as the Marcellus and Utica shale formation, which are in close proximity to the Chicago Hub. The further development of these shale formations could provide an alternate source of gas to the Chicago Hub as well as decrease the northeastern region of the United States’ reliance on natural gas imports from Canada. However, the emergence of the Marcellus and Utica shale plays also provides potential opportunities to expand service on Vector.

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 has intensified its oversight of financial reporting, risk standards and affiliate rules and the Pipeline and Hazardous Materials Safety Administration (PHMSA) has 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

Canadian Midstream consists of the Company’s 71% investment in Cabin located 60 kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin, as well as its 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 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.

Results of Operations

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 2014, throughput volumes exceeded take-or-pay levels as available capacity was sold to third parties.

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.

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 40% of total offshore gas production and 60% 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, 2014 and 2013, respectively. Offshore losses reflected persistent weak gas volumes due to decreased production in the Gulf of Mexico. Offshore adjusted earnings also reflected the absence of earnings from the disposals of certain non-core assets that were finalized in March and November 2014, respectively. Partially offsetting the adjusted losses were 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. Offshore results are expected to improve with a full year of the Jack St. Malo portion of WRGGS and the expected 2015 third quarter completion and in-service of both the Big Foot gas portion of WRGGS and the Big Foot Pipeline.

For the year ended December 31, 2013, Offshore incurred an adjusted loss of $2 million compared with an adjusted loss of $3 million for the year ended December 31, 2012. Positive factors impacting the change in Offshore results included the Venice Condensate Stabilization Expansion (Venice) placed into service in November 2013, cost savings achieved from the Company’s election not to renew windstorm insurance coverage and lower depreciation expense. However, more than offsetting these positive factors were persistent weak gas volumes on the majority of Offshore’s pipelines due to decreased production in the Gulf of Mexico.

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 many of Heidelberg Pipeline’s project variables that impact its cost, with Enbridge bearing the residual capital cost risk after these adjustments have been applied.

Asset Impairment

In December 2012, the Company recorded an impairment charge of $166 million ($105 million after-tax) related to certain of its Offshore assets, predominantly located within the Stingray and Garden Banks corridors in the Gulf of Mexico. The Company had been pursuing alternative uses for these assets; however, due to changing competitive conditions in the fourth quarter of 2012, the Company concluded that such alternatives were no longer likely to proceed. In addition, unique to these assets is their significant reliance on natural gas production from shallow water areas in the Gulf of Mexico that have been challenged by macro-economic factors including prevalence of onshore shale gas production, hurricane disruptions, additional regulation and the low natural gas commodity price environment.

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 exploration activities and producing infrastructure. Offshore diversifies its risk of declining gas production through the construction of crude oil pipelines. To date, crude oil prices have supported stable offshore investment; however, 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 majority of the 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 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

Other includes 1,300 MW of net renewable power generating capacity out of the net enterprise-wide portfolio of 1,600 MW. The balance of the portfolio is held by the Fund. Also included in Other is the Montana-Alberta Tie-Line (MATL), the Company’s first power transmission asset.

To optimize funding of its enterprise-wide slate of growth projects, Enbridge may, from time to time, drop down assets to its sponsored vehicles. In 2012, Greenwich Wind Energy Project (Greenwich), Amherstburg Solar Project (Amherstburg) and Tilbury Solar Project (Tilbury) were transferred to the Fund. Earnings contributions from these assets, net of noncontrolling interests, are reflected within Sponsored Investments from the date the assets were transferred to the Fund. Refer to Sponsored Investments – Enbridge Income Fund – Enbridge Income Fund Drop Down Transactions.

Results of Operations

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 over the past two years.

Adjusted earnings from Other for the year ended December 31, 2013 were $4 million compared with $10 million for the year ended December 31, 2012. The decrease in adjusted earnings was attributable to the transfer of certain renewable energy assets to the Fund in December 2012, as well as lower contributions from the Cedar Point Wind Energy Project due to lower wind resources. Partially offsetting the decrease in adjusted earnings were earnings from Lac Alfred, which commenced commercial operations in phases in 2013.

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 and Enbridge now holds a 67.5% interest in Lac Alfred. The Massif du Sud transaction closed in December 2014 and Enbridge now holds an 80% interest in Massif du Sud.

SPONSORED INVESTMENTS

EARNINGS

	2014		2013		2012
(millions of Canadian dollars)
Enbridge Energy Partners, L.P. (EEP)	197		165		141
Enbridge Energy, Limited Partnership (EELP)	107		38		38
Enbridge Income Fund (the Fund)	125		110		85
Adjusted earnings	429		313		264
EEP - changes in unrealized derivative fair value gains/(loss)	5		(6	)	(2	)
EEP - leak remediation costs	(12	)	(44	)	(9	)
EEP - make-up rights adjustment	(1	)	-		-
EEP - asset impairment loss	(2	)	-		-
EEP - employee severance costs	(1	)	-		-
EEP - leak insurance recoveries	-		6		24
EEP - tax rate differences/changes	-		(3	)	-
EEP - gain on sale of non-core assets	-		2		-
EEP - NGL trucking and marketing investigation costs	-		-		(1	)
EEP - prior period adjustment	-		-		7
The Fund - changes in unrealized derivative fair value gains	3		-		-
The Fund - drop down transaction costs	(2	)	-		-
Earnings attributable to common shareholders	419		268		283

Adjusted earnings from Sponsored Investments were $429 million for the year ended December 31, 2014 compared with $313 million for the year ended December 31, 2013 and $264 million for the year ended December 31, 2012. The increase in adjusted earnings reflected new assets placed into service in EEP, primarily the Line 6B replacement and expansion, along with higher throughput on EEP’s Lakehead and North Dakota System. Enbridge also benefitted from the completion of Line 6B replacement and expansion through its 75% interest in EELP. Within the Fund, higher earnings were primarily driven by an increased asset base and associated earnings impact from the completion of asset drop down from Enbridge.

Sponsored Investments earnings were impacted by the following adjusting items:

· Earnings from EEP for each period included changes in unrealized fair value gains and losses on derivative financial instruments.

· Earnings from EEP for each period 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 a make-up rights adjustment.

· Earnings from EEP for 2014 included an asset impairment loss.

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

· Earnings from EEP for 2013 and 2012 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.

· Earnings from EEP for 2013 included an out-of-period, non-cash deferred income tax adjustment related to a tax law change.

· Earnings from EEP for 2013 included a gain on sale of non-core assets.

· Earnings from EEP for 2012 reflected charges for legal and accounting costs associated with an investigation at a NGL trucking and marketing subsidiary, which was concluded in the first quarter of 2012.

· Earnings from EEP for 2012 reflected a non-recurring out-of-period adjustment.

· Earnings from the Fund for 2014 included unrealized fair value gains on derivative financial instruments.

· Earnings from the Fund for 2014 included costs incurred in relation to a transaction to transfer natural gas and diluent pipeline interests to the Fund. See Sponsored Investments – Enbridge Income Fund – Enbridge Income Fund Drop Down Transactions.

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, 2014, Enbridge’s economic interest in EEP was 33.7% (2013 - 20.6%; 2012 - 21.8%). The Company’s average economic interest in EEP during 2014 was 27.3% (2013 - 21.1%; 2012 - 23.0%). 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.

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 General Partner (GP) of EEP, irrevocably waived its then existing incentive distribution rights (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 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. 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%

Following the Equity Restructuring on July 1, 2014, 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%
First target - cash distributions over US$0.5345 per unit	75%	25%

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 2014, Enbridge received from EEP, incentive distributions of US$39 million (2013 - US$130 million; 2012 - US$116 million). Also in 2014, Enbridge received distributions of US$108 million from Class D units which were issued under the Equity Restructuring discussed above.

Results of Operations

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, have also been a significant contributor to adjusted earnings growth. Positive factors experienced by Canadian Mainline as noted earlier also resulted in higher 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.

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 FERC on June 27, 2014, and effective August 1, 2014, the Lakehead System Toll increased from US$2.17 per barrel to US$2.49 per barrel.

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.

Adjusted earnings from EEP were $165 million for the year ended December 31, 2013 compared with $141 million for the year ended December 31, 2012. The adjusted earnings increased primarily due to distributions received from Enbridge’s May 2013 investment in preferred units of EEP and higher incentive distributions. Also contributing to higher adjusted earnings were contributions from EEP’s liquids business due to higher tolls on EEP’s major liquids pipeline assets and the positive impact of new assets placed into service. Partially offsetting the increase in adjusted earnings were lower volumes on the North Dakota system due to wide crude oil price differentials that made transportation by rail competitive, although tightening crude oil price differentials in the second half of 2013 resulted in some volumes returning to the North Dakota system. EEP’s adjusted earnings also reflected costs related to the completion of hydrostatic testing on Line 14 of its Lakehead System, as well as higher depreciation expense associated with new assets placed into service. Also offsetting the adjusted earnings increase were lower NGL prices and volumes in EEP’s natural gas and NGL businesses and higher operating and administrative expense, primarily from an increased workforce.

Alberta Clipper Drop Down

In September 2014, Enbridge and EEP announced Enbridge’s proposal to transfer 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 announcement, EEP already owned the remaining 33.3% interest in the United States segment of Alberta Clipper. On January 2, 2015, the drop down closed for aggregate consideration of 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 had 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 corresponds to an approximate 10.7 times multiple of 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 April 1, 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 is 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. The line is being expanded in two phases to a capacity of 800,000 bpd through the addition of increased pumping horsepower. 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 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. In response to the release, a unified command structure was established under the jurisdiction of the EPA, the Michigan Department of Natural Resources and Environment and other federal, state and local agencies.

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 which defined the scope requiring additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. EEP submitted its initial proposed work plan required by the EPA on April 4, 2013 and resubmitted the work plan on April 23, 2013 and again on May 1, 2013 based on EPA comments. The EPA approved the Submerged Oil Recovery and Assessment (SORA) work plan with modification on May 8, 2013. EEP incorporated the modification and submitted an approved SORA on May 13, 2013. At this time, EEP has completed substantially all of the SORA.

As of December 31, 2014, regulatory authority transferred from the EPA to the Michigan Department of Environmental Quality (MDEQ). EEP is now working with the MDEQ who 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.

As at December 31, 2014, 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 an increase of US$86 million ($12 million after-tax attributable to Enbridge) as compared with December 31, 2013. On May 28, 2014, the MDEQ’s Water Resource Division approved EEP’s Schedule of Work for the remainder of 2014. The total cost increase of US$86 million during the year ended December 31, 2014, is 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, 2014. 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 continues to monitor the areas affected by the crude oil release from Line 6A of its Lakehead System for any additional requirements; however, the cleanup, remediation and restoration of the areas affected by the release have been completed. On October 21, 2013, the National Transportation Safety Board publicly posted their final report related to the Line 6A crude oil release that occurred in Romeoville, Illinois, 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.

As at December 31, 2014, the total estimated cost for the Line 6A crude oil release is now approximately US$51 million ($7 million after-tax attributable to Enbridge) before insurance recoveries and excluding fines and penalties, which is an increase of US$3 million (nil after-tax attributable to Enbridge) as compared to December 31, 2013 primarily due to additional legal expenses. These costs included emergency response, environmental remediation and cleanup activities with the crude oil release. EEP is pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained.

Insurance Recoveries

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 up for renewal 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, 2014, 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, 2014, 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 the remaining US$145 million 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 has since 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 the lawsuit against the one insurer while the recovery of the remaining US$18 million is awaiting resolution of that lawsuit. While EEP believes those costs are eligible for recovery, there can be no assurance that EEP will prevail in the lawsuit.

Enbridge renewed its comprehensive property and liability insurance programs under which the Company is insured through April 30, 2015 with a liability aggregate limit of US$700 million, including sudden and accidental pollution liability. The deductible applicable to oil pollution events was increased to US$30 million per event, from the previous US$10 million. 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. Approximately seven 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, including direct actions and actions seeking class status. Based on the current status of these cases, the Company does not expect the outcome of these actions to be material.

At December 31, 2014, included in EEP’s estimated costs related to the Line 6B crude oil release is US$48 million in fines and penalties. Of this amount, US$3.7 million related to civil penalties assessed by the PHMSA, which EEP paid during the third quarter of 2012. The total also included an amount of US$40 million related 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, emergency response to environmental events. The cost of compliance with such measures could be significant. Discussions with governmental agencies regarding fines, penalties and injunctive relief are ongoing.

One claim related to 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, and the parties are currently operating under an agreed interim order.

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.

The total estimated cost for the repair and remediation associated with the Line 14 crude oil release remains at approximately US$10 million ($1 million after-tax attributable to Enbridge), inclusive of approximately US$2 million of lost revenues and excluding any fines and penalties. Despite the efforts EEP has made to ensure the reasonableness of its estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. EEP will be pursuing claims under Enbridge’s comprehensive insurance policy, although it does not expect any recoveries to be significant.

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. 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 a 2% GP interest, an approximate 52% limited partner interest and all IDR in MEP. However, EEP’s direct interest in entities or partnerships holding the natural gas and NGL midstream operations reduced from 61% to 48%, with the remaining ownership held by MEP. The completion of 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.

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. Concurrent with the issuance, 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.

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 Enbridge Energy Management, L.L.C. (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, an agreement to drop down Enbridge’s 66.7% interest in the United States segment of Alberta Clipper to EEP was finalized. 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 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 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 $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 from 240,000 bpd to 500,000 bpd 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.

Earnings from EELP were $38 million for both the years ended December 31, 2013 and 2012. EELP earnings were comparable between years due to offsetting factors. Alberta Clipper earnings decreased and reflected lower tolls, which took effect April 1, 2013. Variations in Alberta Clipper earnings from the regulated allowed return on rate base are recovered from or refunded to shippers in the following year. The decrease in Alberta Clipper earnings were offset by the positive impact of incremental revenues from several small components of the Eastern Access project which were placed into service in 2013, including the Line 5 expansion.

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. In conjunction with Liquids Pipelines, 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 constructions 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.

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 best efforts on 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

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.

ENBRIDGE INCOME FUND

The Fund has investments in three core businesses: renewable and alternative power generation (Green Power); crude oil and liquids pipeline transportation and storage (Liquids Transportation and Storage); and a 50% interest in Alliance Pipeline (Natural Gas Transmission). Within Green Power, the Fund has interests in over 500 MW of net renewable and alternative power generation capability. Liquids Transportation and Storage operates a crude oil gathering system and trunkline pipeline in southern Saskatchewan and southwestern Manitoba, connecting to Enbridge’s mainline pipeline to the United States (the Saskatchewan System). The Fund’s Liquids Transportation and Storage also includes the Canadian portion of the Bakken Expansion Program, interests in Southern Lights Pipeline, and the Hardisty Contract Terminals and Hardisty Storage Caverns located near Hardisty, Alberta.

Enbridge Income Fund Drop Down Transactions

In November 2014, the Fund 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. 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 Enbridge Commercial Trust (ECT), a subsidiary of the Fund. Under the agreement, Enbridge provided bridge debt financing (Bridge Financing) to the Fund in the form of an $878 million long-term note payable by the Fund and bearing interest of 5.5% per annum. In November 2014, the Fund 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 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 was reduced from 67.3% to 66.4% upon completion of the transaction.

In December 2012, the Fund acquired the Hardisty Storage Caverns, Hardisty Contract Terminals and the Greenwich, Amherstburg and Tilbury projects from Enbridge and its wholly-owned subsidiaries for an aggregate purchase price of approximately $1.2 billion, financed in part by the issuance of additional ordinary trust units of the Fund to ENF and ECT preferred units to Enbridge. ENF in turn issued additional common shares to the public and to Enbridge. Enbridge also provided Bridge Financing to the Fund for the balance of the purchase price, which was repaid in December 2012. Enbridge’s overall economic interest in the Fund was reduced from 69.2% to 67.7% upon completion of the transaction.

The asset transfers described above occurred between entities under common control of Enbridge, and the intercompany gains realized by the selling entities in each of the years ended December 31, 2014 and 2012 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 charges of $157 million and $56 million in 2014 and 2012, respectively.

Through these transactions, 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 and $213 million for the years ended December 31, 2014 and 2012, respectively, as presented within Financing Activities on the Consolidated Statements of Cash Flows.

In December 2014, Enbridge also announced a proposed transfer of Canadian Liquids Pipelines and certain renewable energy assets to the Fund. For further details, refer to Canadian Restructuring Plan.

Results of Operations

Adjusted earnings for the Fund 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 in November 2014 as well as strong performance from the Fund’s liquids business. Partially offsetting the increase in adjusted earnings were lower wind resources across several of the Fund’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 were also positively impacted by higher preferred unit distributions received from the Fund.

Earnings for the Fund for the year ended December 31, 2013 were $110 million compared with $85 million for the year ended December 31, 2012. The increase in earnings was attributable to earnings from crude oil storage and renewable energy assets acquired from Enbridge and its wholly-owned subsidiaries in December 2012. Earnings were also positively impacted by higher preferred unit distributions received from the Fund and earnings from the Bakken Expansion Program, which commenced operations in March 2013. Partially offsetting these sources of earnings growth was higher interest expense and a one-time charge recognized in the first quarter of 2013 related to the write-off of a regulatory deferral balance for which recoverability is no longer probable.

Westspur Settlement

On April 1, 2013, the Fund 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 establishes 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 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

On July 15, 2013, Alliance Pipeline announced that beginning on August 15, 2013, customers could express interest in shipping on the Alliance Pipeline for periods following the December 2015 expiry of the majority of the existing contracts. Alliance Pipeline outlined the services to be offered as well as the precedent agreement process to be followed. On May 22, 2014, Alliance Canada filed an application with the NEB for regulatory approval of its new services offering and the related tolls and tariff provisions required to implement the new services. Alliance US intends to file an application with the FERC in mid-2015 regarding its new services offering. Given its unique ability to cost-effectively transport liquids-rich natural gas, and the supply growth in basins it runs through, it is expected that the Alliance Pipeline will be well-utilized for the foreseeable future as evidenced by good progress made in securing precedent agreements with shippers. As of February 2015, over 90% of total targeted capacity, a combination of receipt and full path, has been secured with an average contract length of almost five years.

Incentive and Management Fees

Enbridge receives an annual base management fee for administrative and management services it provides to the Fund, plus incentive fees. Incentive fees are paid to Enbridge based on cash distributions paid by the Fund that exceed a base distribution amount. In 2014, the Company received incentive fees of $23 million (2013 - $20 million; 2012 - $12 million) before income taxes. Enbridge also provides management services to ENF. No additional fee is charged to ENF for these services provided the Fund is paying a fee to Enbridge.

BUSINESS RISKS

The risks identified below are specific to the Fund’s three core businesses: Green Power; Liquids Transportation and Storage; and Alliance Pipeline. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks.

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 Fund. Additionally, inefficiencies or interruptions of Green Power facilities due to operational disturbances could also impact earnings. The Company may mitigate 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.

Liquids Transportation and Storage

Asset Utilization

Asset utilization risk for the Fund’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’s assets. The Fund is also exposed to throughput risk under certain tolling agreements applicable to the Saskatchewan System assets.

The Fund 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’s assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on the Fund’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.

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 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 best 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 substantially all of its long-term capacity contracts extend until late 2015. However, excess capacity and depressed natural gas and crude prices have led to the prospect of a reduction or deferral of investment in upstream gas development, and could negatively impact the ability of Alliance Pipeline to recontract when its newly secured contracts expire beyond 2015. Additionally, increased supply from new shale developments including the Marcellus and Utica shale plays could displace gas from the WCSB to the United States midwest, further increasing re-contracting risk.

Re-contracting risk is partially mitigated as Alliance Pipeline is well-positioned to deliver incremental liquids-rich gas production from developments in the Montney, Duvernay and Bakken regions to the Aux Sable NGL fractionation plant. Alliance Pipeline is also engaged with market participants in developing new receipt facilities and services to expand its reach in transporting liquids-rich gas to premium markets. As noted above, Alliance Pipeline recontracting efforts are well advanced.

Competition

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

Economic Regulation

Alliance Pipeline is subject to regulation by the NEB in Canada and the FERC in the United States. If tolls, rates, or tariffs are protested, the timing and amount of 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. On a yearly basis, following consultation with shippers, Alliance Pipeline files its annual rates with the NEB and FERC for approval.

CORPORATE

EARNINGS

	2014		2013		2012
(millions of Canadian dollars)
Noverco Inc. (Noverco)	43		54		27
Other Corporate	(69	)	(82	)	(57	)
Adjusted loss	(26	)	(28	)	(30	)
Noverco - changes in unrealized derivative fair value gains/(loss)	(5	)	4		(10	)
Noverco - equity earnings adjustment	-		-		(12	)
Other Corporate - changes in unrealized derivative fair value loss	(378	)	(306	)	(22	)
Other Corporate - tax on intercompany gains on sale of assets	(157	)	-		(56	)
Other Corporate - gain on sale of investment	14		-		-
Other Corporate - drop down transaction costs	(6	)	-		-
Other Corporate - foreign tax recovery	-		4		29
Other Corporate - impact of tax rate changes	-		18		(11	)
Other Corporate - asset impairment loss	-		(6	)	-
Other Corporate - unrealized foreign exchange loss on
translation of intercompany balances, net	-		-		(17	)
Loss attributable to common shareholders	(558	)	(314	)	(129	)

Total adjusted loss from Corporate was $26 million for the year ended December 31, 2014 compared with adjusted losses of $28 million for the year ended December 31, 2013 and $30 million for the year ended December 31, 2012. 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 in 2014 compared with 2013 and mainly reflected stronger operating earnings from Gaz Metro Limited Partnership (Gaz Metro). Higher volumes within Gaz Metro’s Quebec-based gas distribution franchise area, contributions from a full year of operations of power distribution assets acquired by Noverco in mid-2012, along with the gain on sale and equity earnings true-up adjustment noted above, drove higher Noverco adjusted earnings in 2013 compared with 2012. Adjusted loss in Corporate continued to reflect higher preference share dividends from an increase in the number of preference shares outstanding over the past two years; however, this was largely offset in 2014 by lower net Corporate segment finance costs.

Corporate loss was impacted by the following adjusting items:

· Noverco earnings for each period included changes in unrealized fair value gains and losses on derivative financial instruments.

· Noverco earnings for 2012 included an unfavourable equity earnings adjustment related to prior periods.

· 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 2014 and 2012 were impacted by tax on intercompany gains on sales. See Sponsored Investments – Enbridge Income Fund – Enbridge Income Fund Drop Down Transactions.

· Other Corporate loss for 2014 included a gain on sale of an investment.

· Other Corporate loss for 2014 included transaction costs associated with the proposed Canadian Liquids Pipelines financial restructuring plan, refer to Canadian Restructuring Plan and costs incurred in relation to a transaction to transfer natural gas and diluent pipeline interests to the Fund. See Sponsored Investments – Enbridge Income Fund – Enbridge Income Fund Drop Down Transactions.

· Other Corporate loss for 2013 and 2012 were reduced by recovery of taxes related to a historical foreign investment.

· Other Corporate loss for 2013 and 2012 were impacted by tax rate changes.

· Other Corporate loss for 2013 included charges related to asset impairment losses.

· Other Corporate loss for 2012 included net unrealized foreign exchange loss on the translation of foreign-denominated intercompany balances.

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, 2013 and 2012, 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 and 2012 transactions 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.

On March 22, 2012, Noverco sold 22.5 million Enbridge common shares through a secondary offering. Enbridge’s share of the proceeds of approximately $317 million was received as a dividend from Noverco on May 18, 2012 and was used to pay a portion of the Company’s quarterly dividend on June 1, 2012. This portion of the quarterly 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%.

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	1	Per Share Base Redemption Value	2	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 record 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. However, until the Canadian Restructuring Plan is complete, which is targeted for mid-2015, the Company may not access the public markets as regularly as in recent previous years. The Company has sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables the Company 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.

In 2014, Enbridge continued to actively employ its sponsored vehicles to enhance its enterprise-wide funding program. Following a series of actions in 2013 by Enbridge to enhance liquidity at EEP for the next several years until its growth capital commitments are permanently funded, Enbridge took a further step in June 2014 to re-establish EEP as a cost-effective sponsored vehicle by restructuring EEP’s equity. The Equity Restructuring is expected to benefit Enbridge in the longer-term by lowering EEP’s cost of capital and improving its growth outlook, thus increasing the incentive distributions to Enbridge and enhancing its ability to undertake drop down transactions and third party acquisitions. For further detail to the Equity Restructuring, refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Equity Restructuring.

Following the Equity Restructuring, Enbridge and EEP announced in September 2014 a proposed drop down of Enbridge’s 66.7% interest in the United States segment of the Alberta Clipper Pipeline to EEP, which subsequently closed in January 2015. 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.

In November 2014, Enbridge finalized an agreement to transfer natural gas and diluent pipeline interest to the Fund, a transaction that provided Enbridge approximately $1.2 billion of net funding for its growth capital program. Refer to Sponsored Investments – Enbridge Income Fund – Enbridge Income Fund Drop Down Transactions.

Finally, in December 2014, Enbridge announced the Canadian Restructuring Plan which accelerates the sponsored vehicle financing strategy. The Canadian Restructuring Plan contemplates the drop down of approximately $17 billion of Enbridge’s Canadian Liquids Pipelines business and certain renewable energy assets to the Fund and is targeted to close mid-2015. For further details, refer to Canadian Restructuring Plan.

In accordance with its funding plan, the Company completed the following issuances in 2014:

· Corporate - $460 million of common shares; $1,400 million of preference shares; $1,530 million of medium-term notes; US$1,500 million of senior notes;

· Liquids Pipelines - Southern Lights Pipeline - $352 million and US$1,061 million of private placement notes;

· Gas Distribution - EGD - $730 million of medium-term notes;

· Sponsored Investments - The Fund - $1,080 million of medium-term notes; MEP - US$400 million of private senior notes.

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, Enbridge also bolstered its committed bank credit facilities in 2014. In addition to ensuring adequate liquidity, the Company 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, 2014 and 2013.

		December 31, 2014			December 31, 2013
	Maturity Dates	Total Facilities	Draws1	Available	Total Facilities
(millions of Canadian dollars)
Liquids Pipelines	2016	300	163	137	300
Gas Distribution	2016-2019	1,008	943	65	707
Sponsored Investments	2016-2019	4,531	2,745	1,786	4,781
Corporate	2016-2019	12,772	6,223	6,549	11,775
Total committed credit facilities2		18,611	10,074	8,537	17,563

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

2 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. Excluded from December 31, 2014 total facilities above was Southern Lights project financing facilities of $28 million (2013 - $1,570 million). Included in the 2013 facilities for Southern Lights were $63 million for debt service reserve letters of credit.

In addition to the committed credit facilities noted above, the Company also has $361 million (2013 - $35 million) of uncommitted demand credit facilities, of which $80 million (2013 - $17 million) was unutilized as at December 31, 2014.

The Company’s net available liquidity of $9,291 million at December 31, 2014 was inclusive of $1,261 million of unrestricted cash and cash equivalents and net of bank indebtedness of $507 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, 2014, 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 obtain and maintain a strong 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, 2014, the Company’s debt capitalization ratio was 63.1% compared with 58.2% as at December 31, 2013.

The Company invests a portion of its surplus cash in short-term investment grade instruments with creditworthy counterparties. Short-term investments were $308 million as at December 31, 2014 compared with $85 million as at December 31, 2013. Surplus cash at December 31, 2014 provides financing flexibility and will 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 $47 million related to cash collateral and for specific shipper commitments. Cash and cash equivalents held by EEP and the Fund 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. 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, 2014 and 2013 the Company had a negative working capital position of $296 million and $967 million, respectively, which contemplates the realization of assets and the liquidation of liabilities. In both periods, the major contributing factor is the funding 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, 2014, the net available liquidity totalled $9,291 million. In addition, it is anticipated that any current maturities of long-term debt will be refinanced upon maturity.

December 31,	2014	2013
(millions of Canadian dollars)
Cash and cash equivalents1	1,308	790
Accounts receivable and other2	5,745	5,021
Inventory	1,148	1,115
Assets held for sale3	-	17
Bank indebtedness	(507)	(338)
Short-term borrowings	(1,041)	(374)
Accounts payable and other4	(6,524)	(6,710)
Interest payable	(264)	(228)
Environmental liabilities	(161)	(260)
Working capital	(296)	(967)

1 Includes Restricted cash.

2 Includes Accounts receivable from affiliates.

3 Net of current liabilities held for sale.

4 Includes Accounts payable to affiliates.

OPERATING ACTIVITIES

Cash generated from operating activities was $2,547 million for the year ended December 31, 2014 (2013 - $3,341 million; 2012 - $2,874 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 have been positively impacted in part by new Liquids Pipelines and Sponsored Investments assets placed into service over the past three years, as well as strong operating performance from the Company’s core businesses, which included higher throughput from growing crude oil supply from western Canada and higher downstream refinery demand as discussed in Performance Overview. Partially offsetting these positive factors for 2014 were higher financing costs as the Company significantly advanced its funding and liquidity strategy in support of its long-term growth plan, as well as lower common dividends paid by Noverco compared with 2012. During the year ended December 31, 2014, no common dividends were paid by Noverco, whereas in 2013 a one-time common dividend of $248 million (2012 - $317 million) was paid upon realization of a gain on the disposition of a portion of its investment in Enbridge shares.

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

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 natural gas prices and colder than normal weather in the gas distribution business during the first quarter which resulted in the Company accumulating a significant regulatory receivable.

In 2013, the year-over-year change in cash from operating activities was impacted by a favourable variance of $251 million for changes in operating assets and liabilities, mainly attributable to higher activity in the Company’s marketing and gas distribution businesses, which had higher accounts payable balances resulting from higher purchases, partially offset by increases in accounts receivable and inventory balances.

INVESTING ACTIVITIES

Cash used in investing activities was $11,891 million for the year ended December 31, 2014 (2013 - $9,431 million, 2012 - $6,204 million) which represents an increase on a year-over-year basis primarily due to additions to property, plant and equipment associated with the construction of the Company’s expansion initiatives as described in Growth Projects – Commercially Secured Projects. A summary of additions to property, plant and equipment for the years ended December 31, 2014, 2013 and 2012 is as follows:

Year ended December 31,	2014	2013	2012
(millions of Canadian dollars)
Liquids Pipelines	5,914	4,359	1,926
Gas Distribution	603	533	445
Gas Pipelines, Processing and Energy Services	678	744	933
Sponsored Investments	3,269	2,565	1,886
Corporate	60	34	4
Total capital expenditures	10,524	8,235	5,194

Other notable investing activities during 2014, 2013 and 2012 included the funding of various investments in joint ventures, primarily the Seaway Pipeline Twinning/Extension projects and the Texas Express NGL System. Additionally, investing activities included the acquisition of interests in various projects, most notably Magic Valley and Wildcat wind farms in 2014, and Silver State North Solar Project and Pipestone and Sexsmith in 2012.

FINANCING ACTIVITIES

Cash generated from financing activities was $9,770 million for the year ended December 31, 2014 (2013 - $5,070 million, 2012 - $4,395 million). The cash inflow from financing activities has increased over the 2012 to 2014 time frame as the Company executed its funding and liquidity strategy in support of its long-term growth plan.

During the year ended December 31, 2014, the Company increased its overall debt by $9,000 million (2013 - $3,392 million, 2012 - $1,795 million). The most significant contributor of the increase was the issuance of medium-term and senior notes, net of repayments, of $5,573 million during 2014 (2013 - $2,185 million, 2012 - $1,850 million) and the securement of additional credit facilities together with increased draws on such facilities and commercial paper, net of repayments, of $2,693 million during 2014 (2013 - $1,557 million, 2012 – $307 million of net repayments).

Furthermore, the Company issued preference shares during 2014 for net proceeds of $1,365 million (2013 - $1,428 million, 2012 - $2,634 million), as well as common shares for net proceeds of $478 million (2013 - $628 million, 2012 - $465 million). The additional preference and common shares outstanding during the year together with an 11% increase in the common share dividend rate, gave rise to an increase in dividends paid in 2014 compared with 2013 and 2012.

Financing activities also included transactions between the Company’s Sponsored Investments and their public unitholders, also referred to as noncontrolling interests. During 2014, EEP, MEP and the Fund made distributions, net of contributions, of $79 million. During 2013 and 2012, sponsored vehicles received contributions, net of distributions, of $474 million and $191 million, primarily as a result of their equity issuances to the public.

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, 2014, dividends declared were $1,177 million (2013 - $1,035 million), of which $749 million (2013 - $674 million) were paid in cash and reflected in financing activities. The remaining $428 million (2013 - $361 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, 2014 and 2013, 36.4% and 34.9%, respectively, of total dividends declared were reinvested.

On December 3, 2014, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2015 to shareholders of record on February 16, 2015.

Common Shares	$0.46500
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	35,457	2,043	4,263	2,817	26,334
Capital and operating leases	1,250	120	222	128	780
Long-term contracts	15,065	5,965	3,026	1,952	4,122
Pension obligations2	109	109	-	-	-
Total contractual obligations	51,881	8,237	7,511	4,897	31,236

1 Excludes interest. 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 2015. Contributions are made in accordance with independent actuarial valuations as at December 31, 2014. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.

CAPITAL EXPENDITURE COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials totalling $4,401 million which are expected to be paid over the next five years.

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)	852,086,414
Stock Options - issued and outstanding (18,239,010 vested)	35,241,492

1 Outstanding share data information is provided as at February 9, 2015.

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

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 attributable to common shareholders	390		756		(80	)	88		1,154
Earnings per common share	0.48		0.92		(0.10	)	0.11		1.39
Diluted earnings 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

2013	Q1	Q2		Q3		Q4		Total
(millions of Canadian dollars, except for per share amounts)
Revenues	7,897	7,730		8,998		8,293		32,918
Earnings attributable to common shareholders	250	42		421		(267	)	446
Earnings per common share	0.32	0.05		0.52		(0.33	)	0.55
Diluted earnings per common share	0.31	0.05		0.51		(0.33	)	0.55
Dividends paid per common share	0.3150	0.3150		0.3150		0.3150		1.26
EGD - warmer/(colder) than normal weather	6	(2	)	-		(13	)	(9)
Changes in unrealized derivative fair value (gains)/loss	207	246		(223	)	613		843

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 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 impacted the consolidated quarterly earnings included:

· Included in the fourth quarter of 2014 was the tax impact of an asset transfer between entities under common control of Enbridge. The intercompany gain realized by the selling entity has been eliminated from the Consolidated Financial Statements of Enbridge. However, as the transaction involved sale of partnership units, the tax consequences has remained in consolidated earnings and resulted in a charge of $157 million.

· Included in first and fourth quarter earnings for 2014 were $43 million and $14 million after-tax gain on the disposal of non-core Offshore assets. 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; and $24 million, $6 million, $5 million and $9 million were recognized in the first, second, third and fourth quarters of 2013. 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. Earnings also included insurance recoveries associated with the Line 6B crude oil release of $6 million in the second quarter of 2013.

· Included in earnings are after-tax costs of $4 million in the third quarter of 2014 as well as $40 million, $13 million and $3 million incurred respectively in the second, third and fourth quarters of 2013, 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 $4 million recognized in the second quarter and fourth quarter of 2014, respectively.

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 in Growth Projects – Commercially Secured Projects and Growth Projects – Other Projects Under Development.

RELATED PARTY TRANSACTIONS

Other than the drop down transactions between Enbridge and its sponsored vehicles previously mentioned, all related party transactions are undertaken 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, 2014 (2013 - $6 million; 2012 - $6 million).

Certain wholly-owned subsidiaries within Gas Distribution, Gas Pipelines, Processing and Energy Services and Sponsored Investment 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, 2014 were $256 million (2013 - $222 million; 2012 - $127 million).

Certain wholly-owned subsidiaries within Gas Distribution and Gas Pipelines, Processing and Energy Services made natural gas and NGL purchases of $315 million (2013 - $99 million; 2012 - $15 million) from several joint venture affiliates during the year ended December 31, 2014.

Natural gas sales of $58 million (2013 - $10 million; 2012 - $7 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, 2014.

Amounts receivable from affiliates include a series of loans to Vector totalling $183 million (2013 - $181 million), included in Deferred amounts and other assets, which require quarterly interest payments at annual interest rates from 4% to 8%.

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 expense 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 expense, 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 2.1%.

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 4.1%.

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

Commodity Price Risk

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

Equity Price Risk

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

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, before the effect of income taxes.

Year ended December 31,	2014		2013		2012
(millions of Canadian dollars)
Amount of unrealized gains/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	8		56		(12	)
Interest rate contracts	(1,086	)	814		(46	)
Commodity contracts	50		(9	)	52
Other contracts	13		(2	)	(3	)
Net investment hedges
Foreign exchange contracts	(113	)	(81	)	1
	(1,128	)	778		(8	)
Amount of gains/(loss) reclassified from Accumulated other comprehensive income (AOCI) to earnings (effective portion)
Foreign exchange contracts1	8		(8	)	1
Interest rate contracts2	101		107		(1	)
Commodity contracts3	4		1		(3	)
Other contracts4	(7	)	-		2
	106		100		(1	)
Amount of gains/(loss) reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)
Interest rate contracts2	216		51		23
Commodity contracts3	(6	)	(3	)	(3	)
	210		48		20
Amount of gains/(loss) from non-qualifying derivatives included in earnings
Foreign exchange contracts1	(936	)	(738	)	120
Interest rate contracts2	4		(10	)	(2	)
Commodity contracts3	1,031		(496	)	(765	)
Other contracts4	7		(3	)	(2	)
	106		(1,247	)	(649	)

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

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

3 Reported within Transportation and other services 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.

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, until the Canadian Restructuring Plan is complete, which is targeted for mid-2015, the Company may not access the public markets as regularly as recent previous years. The Company has sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables the Company to fund all anticipated requirements for approximately one year without accessing the capital markets. The Company is in compliance with all the terms and conditions of its committed credit facilities as at December 31, 2014. 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 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, foreign exchange, commodity and share) 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;

· 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, Aboriginal and Native American Policy and the Neutral Footprint Initiative).

The Company’s actions noted above are the key mitigation action against negative public opinion; however, the public opinion risk can not 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.

Project Execution

As the Company increases its slate of growth projects, it continues to focus on completing projects safely, on-time and on-budget. However, the Company faces the challenge of scaling the business to manage an unprecedented number of commercially secured growth projects. 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 through Major Projects and through this group the Company aims 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.

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 pricing 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.

Human Resources

Like many other companies in the energy sector, Enbridge faces a risk that it will be unable to attract and retain the necessary skilled people resources to fulfill its growth plan. Factors that could impact Enbridge’s ability to secure these resources include labour shortages and the shortage of technically skilled workers; rates of retirement and turnover and the ability to successfully transfer knowledge; and retaining Enbridge’s reputation as a great employer. As the Company continues through a sustained period of growth, attracting and retaining adequate personnel who adhere to Enbridge’s values will be critical to achieving the Company’s growth plan.

Operational and Economic Regulation

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 or operating restrictions 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 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 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 constructions 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 best efforts on 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.

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.

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 reinforcement project, which is expected to be completed in late 2015, will be a key mitigation as the project will provide significant diversification of gas supply to EGD’s distribution network and will further reduce the likelihood of a service interruption incident.

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. 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. 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.

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.

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, 2014 of $53,830 million (2013 - $42,279 million), or 73.9% 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.

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 expense in operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities. Also, the Company records regulatory assets and liabilities to recognize the economic effects of the actions of the regulator. 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. On refund or recovery of this difference, no earnings impact is recorded. As at December 31, 2014, the Company’s significant regulatory assets totalled $2,160 million (2013 - $1,138 million) and significant regulatory liabilities totalled $962 million (2013 - $1,016 million). 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.

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 actual return on plan assets exceeded the expected return on plan assets by $58 million for the year ended December 31, 2014 (2013 - $101 million) as disclosed in Note 25, Retirement and Postretirement Benefits, to the 2014 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, 2014 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	205	21	18	-
Decrease in expected return on assets	-	9	-	-
Decrease in rate of salary increase	(44)	(9)	-	-

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 29, Commitments and Contingencies, of the 2014 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 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.

In May 2009, the NEB released a report on the financial issues associated with pipeline abandonment and established a goal for pipelines regulated under the NEB Act to begin collecting and setting aside funds to cover future abandonment costs no later than January 1, 2015. Subsequently, the NEB issued revised “base case assumptions” based on feedback from member companies. Companies were given the option to follow the base case assumptions or to submit pipeline specific applications. On November 29, 2011, as required by the NEB, the Company filed its estimated abandonment costs for its regulated pipeline systems within EPI and Enbridge Pipelines (NW) Inc. (Group 1 companies) and Enbridge Southern Lights GP Inc., Enbridge Bakken Pipeline Company Inc., Enbridge Pipelines (Westspur) Inc., Vector Pipelines Limited Partnership, Niagara Gas Transmission Limited and 2103914 Canada Limited (Group 2 companies).

In the fourth quarter of 2012, the NEB held a hearing on the abandonment costs estimates for Group 1 companies and issued its decision on February 14, 2013. The outcome does not materially impact tolls. On February 28, 2013, Group 1 companies filed a proposed process and mechanism to set aside the funds for future abandonment costs and chose the trust as the appropriate set-aside mechanism to hold pipeline abandonment funds. On May 31, 2013, the Group 1 companies filed collection mechanism applications and the Group 2 companies filed both their set-aside and collection mechanism applications. Once the set-aside and collection mechanism is approved by the NEB, both Group 1 and Group 2 companies can start to recover these costs from shippers through tolls in accordance with the NEB’s determination that abandonment costs are a legitimate cost of providing service and are recoverable upon NEB approval from users of the system. The collections began in 2015.

All applications by the Company will require NEB approval. The NEB hearings commenced January 14, 2014, covering both the set-aside mechanism applications and the collection mechanism applications for both Group 1 and Group 2 companies. The NEB released its decision on May 29, 2014 approving both the set aside mechanism and collection mechanisms for all of the Enbridge Group 1 companies and Group 2 companies.

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 2014, the Company recognized ARO in the amount of $177 million. Of this amount, $74 million related to the decommissioning of certain portions of Line 6B of EEP’s Lakehead System and $103 million related to the Canadian and United States portions of the L3R Program announced in March 2014.

CHANGES IN ACCOUNTING POLICIES

ADOPTION OF NEW STANDARDS

Obligations Resulting from Joint and Several Liability Arrangements

Effective January 1, 2014, the Company retrospectively adopted Accounting Standards Update (ASU) 2013-04 which provides measurement and disclosure guidance for obligations with fixed amounts at a reporting date resulting from joint and several liability arrangements. There was no material impact to the consolidated financial statements for the current or prior periods presented as a result of adopting this update.

Parent’s Accounting for the Cumulative Translation Adjustment

Effective January 1, 2014, the Company prospectively adopted ASU 2013-05 which provides guidance on the timing of release of the cumulative translation adjustment into net income when a disposition or ownership change occurs related to an investment in a foreign entity or a business within a foreign entity. There was no material impact to the consolidated financial statements as a result of adopting this update.

Pushdown Accounting for Business Combinations

Effective November 18, 2014, the Company prospectively adopted ASU 2014-17 which provides an acquired entity with the option to apply pushdown accounting in its separate financial statements upon the occurrence of a change-in-control event. There was no impact to the consolidated financial statements as a result of adopting this update.

FUTURE ACCOUNTING POLICY CHANGES

Extraordinary and Unusual Items

ASU 2015-01 was issued in January 2015 and eliminates the concept of extraordinary items from GAAP. Entities will no longer be required to separately classify and present extraordinary events in the income statement, net of tax, after income from continuing operations. This accounting update is effective for annual and interim reporting periods beginning after December 15, 2015 and may be applied prospectively or retrospectively. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements.

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 is currently assessing the impact of the new standard 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, eliminates the concept of a development stage entity from U.S. GAAP and removes the related incremental reporting requirements. The removal of the development stage entity reporting requirements is effective for annual reporting periods beginning after December 15, 2014 and is not expected to have a material impact on the Company’s consolidated financial statements. The consolidation guidance was also amended 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. The new standard is effective for annual and interim periods beginning on or after December 15, 2016 and may be applied on either a full or modified retrospective basis.

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

ASU 2014-08 was issued in April 2014 and changes the criteria and disclosures for reporting discontinued operations. It is anticipated that, in general, the revised criteria will result in fewer transactions being categorized as discontinued operations. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2014 and is to be applied prospectively.

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, 2014, 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.