Exhibit 99.7

ENBRIDGE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS

December 31, 2013

MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (MD&A) dated February 14, 2014 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, 2013, 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.

In connection with the preparation of the Company’s first quarter consolidated financial statements, an error was identified in the manner in which the Company historically recorded deferred regulatory assets associated with the difference between depreciation expense calculated in accordance with U.S. GAAP and negotiated depreciation rates recovered in transportation tolls for certain of its regulated operations. The error was not material to any of the Company’s previously issued consolidated financial statements; however, as discussed in Note 4, Revision of Prior Period Financial Statements, to the consolidated financial statements as at December 31, 2013, prior year comparative financial statements have been revised to correct the effect of this error. This non-cash revision did not impact cash flows for any prior period. The discussion and analysis included herein is based on revised financial results for the year ended December 31, 2013 or other comparative periods as indicated.

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 1,800 megawatts (MW) of renewable and alternative energy generating capacity and is expanding its interests in wind, solar and geothermal facilities. Enbridge has approximately 10,000 employees and contractors, 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, Southern Lights Pipeline, Seaway 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.

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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 United States portion of the Alliance System (Alliance Pipeline US), 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 System (Alliance). The energy services businesses undertake physical commodity marketing activity and logistical services, refinery supply services and manage the Company’s volume commitments on the Alliance, Vector and other pipeline systems.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 20.6% ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s 66.7% investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, Limited Partnership (EELP) and an overall 67.3% 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, crude oil and liquids pipeline and storage businesses in western Canada and a 50% interest in the Canadian portion of the Alliance System (Alliance Pipeline Canada).

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.

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PERFORMANCE OVERVIEW

	Three Months Ended				Year Ended
	December 31,				December 31,
	2013		2012		2013		2012		2011
(millions of Canadian dollars, except per share amounts)
Earnings attributable to common shareholders
Liquids Pipelines	46		130		427		697		470
Gas Distribution	80		127		129		207		(88	)
Gas Pipelines, Processing and Energy Services	(325	)	32		(68	)	(377	)	328
Sponsored Investments	79		72		268		283		268
Corporate	(151	)	(136	)	(314	)	(129	)	(171	)
Earnings/(loss) attributable to common shareholders from continuing operations	(271	)	225		442		681		807
Discontinued operations - Gas Pipelines, Processing and Energy Services	4		(79	)	4		(79	)	(6	)
	(267	)	146		446		602		801
Earnings/(loss) per common share	(0.33	)	0.19		0.55		0.78		1.07
Diluted earnings/(loss) per common share	(0.32	)	0.18		0.55		0.77		1.05
Adjusted earnings1
Liquids Pipelines	205		177		770		655		501
Gas Distribution	67		63		176		176		173
Gas Pipelines, Processing and Energy Services	17		42		203		176		180
Sponsored Investments	89		68		313		264		243
Corporate	(16	)	(23	)	(28	)	(30	)	(16	)
	362		327		1,434		1,241		1,081
Adjusted earnings per common share1	0.44		0.42		1.78		1.61		1.44
Cash flow data
Cash provided by operating activities	781		502		3,341		2,874		3,371
Cash used in investing activities	(3,277	)	(2,182	)	(9,431	)	(6,204	)	(5,079	)
Cash provided by financing activities	2,744		1,725		5,070		4,395		2,030
Dividends
Common share dividends declared	261		227		1,035		895		759
Dividends paid per common share	0.3150		0.2825		1.26		1.13		0.98
Revenues
Commodity sales	6,939		4,978		26,039		18,494		20,374
Gas distribution sales	710		585		2,265		1,910		1,906
Transportation and other services	644		1,444		4,614		4,256		4,509
	8,293		7,007		32,918		24,660		26,789
Total assets	57,568		46,800		57,568		46,800		41,130
Total long-term liabilities	28,277		25,227		28,277		25,227		23,958

1Adjusted 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 8.

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Earnings attributable to common shareholders were $446 million ($0.55 per common share) for the year ended December 31, 2013 compared with $602 million ($0.78 per common share) for the year ended December 31, 2012 and $801 million ($1.07 per common share) for the year ended December 31, 2011. The Company has delivered 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 or losses. The Company has a comprehensive long-term economic hedging program to mitigate exposures to interest rate, foreign exchange and commodity prices. The changes in unrealized mark-to-market accounting impacts from this program create volatility in short-term earnings but the Company believes over the long-term it supports reliable cash flows and dividend growth.

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Also impacting the comparability of earnings between fiscal years were certain out-of-period adjustments recognized in 2013, including 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. Regional Oil Sands System also had 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, the Company recognized an out-of-year adjustment of $56 million after-tax reflecting an increase to gas transportation costs which had incorrectly been deferred.

Other significant items 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, 2013, 2012 and 2011 included EEP’s cost estimates of US$302 million ($44 million after-tax attributable to Enbridge), US$55 million ($8 million after-tax attributable to Enbridge) and US$215 million ($33 million after-tax attributable to Enbridge), respectively. The aforementioned costs are before insurance recoveries and excluding 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. Insurance recoveries recorded by EEP for the years ended December 31, 2013, 2012 and 2011 were US$42 million ($6 million after-tax attributable to Enbridge), US$170 million ($24 million after-tax attributable to Enbridge) and US$335 million ($50 million after-tax attributable to Enbridge), respectively, related to the Line 6B crude oil release. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – Insurance Recoveries. Within Liquids Pipelines, 2013 earnings reflected remediation and long-term stabilization costs of approximately $56 million after-tax and before insurance recoveries related to the Line 37 crude oil release that occurred in June 2013. See Liquids Pipelines – Regional Oil Sands System – Line 37 Crude Oil Release.

Fourth quarter earnings drivers were largely consistent with year-to-date trends and continued to include changes in unrealized fair value derivative and foreign exchange gains and losses. Aside from operating factors discussed in Performance Overview – Adjusted Earnings, factors unique to the fourth quarter of 2013 included a further recognition of US$65 million ($9 million after-tax attributable to Enbridge) of costs related to the Line 6B crude oil release and an additional $3 million after-tax accrual related to Line 37 remediation activities.

ADJUSTED EARNINGS

A key tenet of the Company’s investor value proposition is “visible growth”, supported by an ongoing 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 $1.44 per common share in 2011 to $1.61 per common share in 2012 and $1.78 per common share in 2013.

The upward trend in adjusted earnings over these years was predominantly attributable to strong operating performance from the Company’s Liquids Pipelines assets and contributions from new assets placed into service. The Canadian Mainline has performed favourably under the Competitive Toll Settlement (CTS) which took effect mid-2011 and has benefitted from heightened throughput since that time. Strong supply from western Canada and the ongoing effect of crude oil price differentials, whereby demand for discounted crude by United States midwest refiners remained high, drove increased throughput on Canadian Mainline in both 2013 and 2012. New Liquids Pipelines assets placed into service in recent years included the Woodland and Wood Buffalo pipelines which, together with expanded capacity on Seaway Crude Pipeline System (Seaway Pipeline), contributed to adjusted earnings growth in 2013. Renewable energy investments continued to be an important component of Enbridge’s strategy to diversify and sustain longer-term earnings growth. Between 2011 and 2013 Enbridge placed into service five wind farms and two solar farms, and commenced operations of its first power transmission project in mid-2013. Adjusted earnings for the year ended December 31, 2013 also reflected contributions from the Company’s recent entry into the Canadian natural gas midstream infrastructure space.

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Enbridge’s sponsored vehicles, EEP and the Fund, also contributed to the year-over-year adjusted earnings growth. The Fund benefitted from an expanded asset base following the acquisition of assets from Enbridge (drop down transactions) in both 2011 and 2012, as well as completion of the Bakken Expansion Project, a project undertaken jointly with EEP. In addition to expanding its North Dakota regional infrastructure, EEP was also successful in completing several other organic growth projects, including the Texas Express NGL System joint venture and the Ajax Cryogenic Processing Plant (Ajax Plant). EEP’s Lakehead System benefitted from strong volumes in both 2012 and 2013, similar to Canadian Mainline, while its natural gas and NGL businesses continued to experience lower volumes and prices due to declining drilling activity in dry gas basins of the United States as a result of a sustained low natural gas commodity price environment.

Other factors which contributed to changes in adjusted earnings year-over-year included market factors impacting the Company’s Energy Services businesses and its Aux Sable fractionation plant, as well as the Company’s continued activity in the capital markets through the issuance of preference shares and debt to fund future growth projects. After a decrease in adjusted earnings in 2012 compared with 2011 due to unfavourable market conditions, Energy Services earnings increased in 2013 as changing market conditions gave rise to a greater number of and more profitable margin opportunities. Reflecting the opposite trend, Aux Sable adjusted earnings increased in 2012 over 2011 due to new assets being placed into service and higher fractionation margins, but declined in 2013 on lower fractionation margins and lower ethane processing volumes due to ethane rejections.

With respect to the fourth quarter of 2013, many of these same annual trends continued. The primary drivers of quarter-over-quarter adjusted earnings growth were volume increases on Canadian Mainline, contributions from new assets placed into service in Regional Oil Sands System and higher contributions from EEP’s liquids business due to a combination of higher throughput and tolls. Although no full year effect, the fourth quarter of 2013 also included a favourable adjustment in Regional Oil Sands System related to a reduction in third party revenue sharing with the founding shipper on the Athabasca pipeline. Partially offsetting earnings growth in the fourth quarter of 2013 was a loss incurred by Energy Services due to changing market conditions, which gave rise to losses on certain physical positions, in addition to losses on financial contracts intended to hedge the value of committed physical transportation capacity but which were ineffective in doing so in the last three months of the year.

CASH FLOWS

Cash provided by operating activities was $3,341 million for the year ended December 31, 2013, mainly driven by strong operating performance from the Company’s core assets, particularly from Liquids Pipelines, and the cash flow generation from growth projects placed into service in recent years. In addition, during 2013, upon realization of a substantial gain on the disposition of a portion of its investment in Enbridge shares, Noverco paid Enbridge a one-time dividend of $248 million. Partially offsetting these cash inflows were changes in operating assets and liabilities which fluctuate in the normal course due to various factors impacting the timing of cash receipts and payments.

In 2013, the Company was active in the capital markets with the issuance of $1,428 million in preference shares, common shares of approximately $628 million and $2,845 million in medium-term notes and also significantly bolstered its liquidity through the securement of additional 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 net investment in expansion initiatives during 2013, and are expected to provide financing flexibility for the Company’s growth opportunities in 2014.

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DIVIDENDS

The Company has paid common share dividends since it became a publicly traded company in 1953. In December 2013, the Company announced an 11% increase in its quarterly dividend to $0.35 per common share, or $1.40 annualized, effective March 1, 2014. Assuming this currently announced quarterly dividend is annualized for 2014, the Company has generated compound annual average growth of 11.8% since 2004. The Company continues to target a dividend payout of approximately 60% to 70% of adjusted earnings over the longer term. In 2013, the dividend payout was 71% (2012 - 70%; 2011 - 67%) of adjusted earnings per share.

REVENUES

The Company generates revenue from three primary sources: commodity sales, gas distribution sales and transportation and other services. Commodity sales of $26,039 million for the year ended December 31, 2013 (2012 - $18,494 million; 2011 - $20,374 million) were earned through the Company’s 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 revenue which depends more on differences in commodity prices between locations and points in time than on the absolute level of prices.

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

Transportation and other services revenues are earned from the Company’s crude oil and natural gas pipeline transportation businesses and also includes power production revenues from the Company’s portfolio of renewable and power generation assets. For the Company’s transportation assets operating under market-based arrangements, revenues are driven by volumes transported and tolls. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator and, in most cost-of-service based arrangements, is reflective of the Company’s cost to provide the service plus a regulator-approved rate of return. Higher transportation and other services revenues reflected increased throughput on the Company’s core liquids pipeline assets as well as new assets placed into service during 2013.

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

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A to provide the Company’s shareholders and potential investors with information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; and expected costs related to leak remediation and potential insurance recoveries.

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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 expected supply and demand for crude oil, natural gas, NGL and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; expected exchange rates; inflation; interest rates; 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; and weather. Assumptions regarding the expected supply and demand of 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, 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, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service date and expected capital expenditures include: the availability and price of labour and construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals on construction 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 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) provides 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. See Non-GAAP Reconciliations for a reconciliation of the GAAP and non-GAAP measures.

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CORPORATE VISION AND STRATEGY

VISION

Enbridge’s vision is to be the leading energy delivery company in North America. 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 safety and operational reliability, environmental stewardship, customer service, employee satisfaction and community investment. 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 its 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
·     Retain, attract and develop highly capable people

Commitment to Safety and Operational Reliability

The commitment to safety and operational reliability means achieving industry leadership in process, public and personal safety, operational reliability and integrity of the Company’s pipelines and facilities and the protection of the environment. This is the Company’s number one priority and sets the foundation for the strategic plan.

Under the umbrella of the Company’s Operational Risk Management (ORM) Plan introduced in 2011, the Company has undertaken extensive maintenance, integrity and inspection programs across its pipeline systems. The ORM Plan has also bolstered incident response capabilities, employee and public safety and improved communications with landowners and first responders. In 2013, Enbridge established the role of Senior Vice President, Enterprise Safety & Operational Reliability, a new centralized role accountable for defining and executing on an enterprise-wide vision, culture and set of integrated strategies and policies that support the Company’s ORM objectives.

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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, environmental and regulatory compliance. With an approximate $29 billion portfolio of commercially secured 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 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 Financial Strength and Flexibility

The maintenance of adequate financial strength and flexibility is crucial to Enbridge’s growth strategy. Enbridge’s financial 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 or improve its 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.

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 benchmarks with the objective of ensuring the enduring financial strength and stability of the Company.

Secure the Longer-Term Future

Strengthen Core Businesses

Within Liquids Pipelines, strategies are focused on providing access to new markets for growing production from western Canada and the Bakken, optimizing and expanding mainline operations and expanding regional oil sands infrastructure. Through Enbridge’s market access initiatives, shippers will be provided greater connectivity to markets in Ontario, Quebec, the Gulf Coast and upper-midwest helping secure the best pricing for their products depending on crude type. Significant market access programs include Gulf Coast Access, Eastern Access and Light Oil Market Access. In 2013, the Company made significant progress on each of these market initiatives including the completion of the Seaway Pipeline expansion to increase transportation capacity to the Gulf Coast to up to 400,000 barrels per day (bpd) depending on crude oil slate. To facilitate these downstream growth projects and continued growth in base volumes, a number of supporting mainline expansions are being undertaken. In addition, the Company is also focused on maximizing existing operating capacity through optimization initiatives such as improved scheduling and tankage management.

The objective of Regional Oil Sands System expansion is to optimize existing asset corridors to secure incremental supply expected from the western Canadian oil sands over the next decade. The Company currently has approximately $6 billion of regional infrastructure under development, including the expansion and twinning of the Athabasca pipeline; the extension of the Wood Buffalo Pipeline (Wood Buffalo Extension); and the Norlite Pipeline System (Norlite), which will transport diluent from the Edmonton region to oil sands producers.

The Company’s natural gas strategies include leveraging the competitive advantages of its existing assets and expanding its footprint in emerging areas. Combined, Alliance 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 is also evaluating opportunities to expand service offerings in those areas.

Enbridge is also partnering with producers to develop needed Canadian midstream infrastructure. In addition to these onshore strategies, the Company continues to pursue crude oil and natural gas gathering expansion opportunities for ultra-deep projects in the Gulf of Mexico, building on momentum achieved with the Walker Ridge Gas Gathering System (WRGGS), Big Foot Oil Pipeline (Big Foot Pipeline) and Heidelberg Lateral Pipeline (Heidelberg) projects currently under construction.

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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 efforts towards securing investment in additional renewable energy and power transmission facilities, as well as developing opportunities in gas-fired power generation, liquefied natural gas 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.

Enbridge has advanced its renewable power strategy considerably over the past several years and has interests in a renewable energy portfolio with a generation capacity of more than 1,800 MW. Since the beginning of 2013, the Company has been successful in securing several projects, including the Keechi Wind Project (Keechi) in Texas, Blackspring Ridge Wind Project (Blackspring Ridge) in Alberta and the Saint Robert Bellarmin Wind Project in Quebec, which collectively will have the capacity to generate an approximate 500 MW of renewable energy.

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 uphold these values in their interactions with each other, with customers, suppliers, landowners, community members and all others with whom the Company deals, and ensure the Company’s business decisions are consistent with these values. Employees and contractors are required, on an annual basis, to certify their compliance with the Company’s Statement on Business Conduct policy which sets out its requirements and expectations regarding conduct.

Maintain the Company’s Social License to Operate

Earning and maintaining “social license” – the approval and acceptance of 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.

One of Enbridge’s CSR environmental objectives is its Neutral Footprint plan, which includes initiatives to counteract the environmental impact of all Enbridge’s pipeline expansion projects. Neutral Footprint initiatives include:

·planting a tree for every tree the Company removes to build new pipelines and facilities;

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

·generating a kilowatt hour of renewable energy for every kilowatt hour the Company’s expansions consume.

The 2013 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. None of the information contained on, or connected to, the Enbridge website is incorporated or otherwise part of this MD&A.

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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 affect 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.

Retain, Attract 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. People-related focus areas include broadening recruiting efforts beyond traditional industry and geographical reaches, ensuring succession capability through accelerated leadership development programs 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 crucial 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.

Global energy consumption is expected to continue to grow, with the growth in crude oil demand primarily driven by non-Organisation for Economic Co-operation and Development (OECD) regions, such as Asia and the Middle East, with China expected to be the largest single growth market. In OECD countries, including Canada, the United States and western European nations, 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 meet growing global demand outside North America.

In terms of supply, North American crude oil production growth is expected to outpace growth from Organization of the Petroleum Exporting Countries over the 2014 to 2030 time period. The primary driver of the production growth stems from the expansion of shale oil and oil sands production. The emergence of shale oil plays, including the Bakken in North Dakota, have altered the United States crude oil production landscape and is expected to double total United States crude oil production over the next 20 years, although the rate of growth could be tempered by increased environmental regulation in future years. In Canada, the Western Canadian Sedimentary Basin (WCSB) continues to be viewed as one of the world’s largest and most secure supply sources of crude oil. Investment in the WCSB continues to be strong and several new projects and expansions of existing oil sands production facilities have been added or accelerated due to supportive oil prices and increased foreign investment.

The combination of relatively flat domestic demand, growing supply and shortages of pipeline infrastructure, has led to volatile crude oil price differentials in North America. In recent years, an over-supply to land-locked 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. To address these market challenges, crude oil transportation infrastructure will have to undergo a major change in configuration. While producers have sought alternative means of transportation, such as rail, to access higher netback markets in the short-term, pipelines will continue to be the most cost effective means of transportation for the longer-term.

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Enbridge’s role in helping to address the evolving supply and demand fundamentals, and improving netbacks for producers and supply costs to refiners, is to provide expanded pipeline capacity and sustainable connectivity to alternative markets. In 2013, Enbridge added to its growing slate of commercially secured projects within Liquids Pipelines to provide market access solutions and additional regional oil sands infrastructure. The Company’s market access initiatives include the Gulf Coast Access Program, Eastern Access Program and Light Oil Market Access Program, all of which provide producers greater access to North American refinery markets.

Despite these initiatives, and those of competitors, heavy oil prices from western Canada will likely continue to lag behind world prices, heightening the need for 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

The North American natural gas market is transitioning to a better balance as gas production growth has slowed after several years of robust increases. As a result, natural gas prices have firmed modestly over the past year. Natural gas supply remains ample and could respond quickly to rising demand, thereby limiting further price advances. As the economy recovers and natural gas prices remain relatively low, gas demand in the United States is expected to increase, primarily from the power generation and industrial sectors. Within Canada, natural gas demand growth is expected to be driven primarily by continued oil sands development.

The Northeast has become the primary source of United States natural gas supply growth as regional gas production has exceeded demand. The significant resource base within the Marcellus and Utica shale gas plays in the northeastern United States has fundamentally altered the flow pattern of gas in North America and is displacing Gulf Coast and WCSB supplies. While this presents opportunities for new regional infrastructure as natural gas producers seek alternative markets, it may also present challenges for existing infrastructure serving these supply areas.

In a weak natural gas price environment, producers have been shifting 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. Recently, extraction margins have been pressured by robust supply and corresponding weaker prices for ethane. This has led to significant ethane rejection and projects to export increased volumes of propane. The growing NGL supply is also straining the existing infrastructure capacity and causing regional price differentials. With the majority of petrochemical facilities located in the Gulf Coast, additional infrastructure will be required to expand processing facilities and take-away pipeline capacity.

Similar to crude oil, significant differentials exist between North American and world gas prices. While North American gas prices continue to be relatively low, the price for liquefied natural gas (LNG) in global markets is more closely linked to higher crude oil prices, providing 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 changing North American natural gas flow patterns discussed above, there is an increasing probability that one or more projects to export LNG off the west Coast of Canada will proceed.

In response to these evolving natural gas and NGL fundamentals, Enbridge believes it is well positioned to provide value-added solutions to producers. Alliance is uniquely configured to transport liquids-rich gas and is currently evaluating service offerings to best meet the needs of producers. 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. Enbridge is also responding to the need for regional infrastructure with additional investment in Canadian and United States midstream processing and pipeline facilities.

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SUPPLY AND DEMAND FOR RENEWABLE ENERGY

North American economic growth over the longer term is expected to drive growing electricity demand. Given the accelerated pace of retirement of aging coal-fired generation plants in North America after 2015 due to impending emission regulations, significant new generation capacity is expected to be required. 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.

The United States National Renewable Energy Laboratory reports that North America has significant wind and solar resources, with wind alone having the potential to provide capacity for over 10,000 gigawatts of power generation. Solar resources in southwestern states such as Arizona, California and Nevada are considered to be the best in the world for large-scale solar plants. According to Environment Canada, Canada also has an abundance of wind and solar resources with particularly strong wind resources in the northeastern regions.

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 which are not in close proximity to high demand 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 be active in renewable asset development and secured the development of three additional wind farms in 2013; and now has interests in more than 1,800 MW of renewable energy generation capacity. In 2013, Enbridge also completed its first power transmission line, the Montana-Alberta Tie-Line (MATL). The Company will continue to seek new opportunities to grow its portfolio of renewable power generation and power transmission businesses that meet its investment criteria.

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

In 2013, the Company was successful in placing approximately $5 billion of growth projects into service across several business units. Enbridge also added to its slate of commercially secured growth projects which now totals approximately $29 billion.

The Company’s growth initiatives are anchored by three major market access initiatives, supported by several mainline system expansion projects which are designed to ensure that there is sufficient capacity to feed these new extensions. The three major market access initiatives are:

·Gulf Coast Access Program;

·Eastern Access Program; and

·Light Oil Market Access Program.

The $5.8 billion Gulf Coast Access Program includes the Seaway Pipeline, the Flanagan South Pipeline Project 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 $6.2 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 supplement 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, the Sandpiper Project (Sandpiper), Canadian Mainline System Terminal Flexibility and Connectivity and twinning of the Spearhead North pipeline and Line 61 expansion included within the Lakehead System Mainline Expansion. 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.

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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 2013. The Company secured wind power generation projects with a generation capacity of approximately 500 MW and also placed the 300-MW MATL, Enbridge’s first power transmission project, into service.

The table below 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 Acquisition/Reversal/Expansion Twinning/Extension	US$1.3 billion US$1.1 billion	US$1.2 billion US$0.6 billion	2012-2013 2014	Complete Under construction
2.	Suncor Bitumen Blend	$0.2 billion	$0.2 billion	2013	Complete
3.	Athabasca Pipeline Capacity Expansion	$0.4 billion	$0.4 billion	2013 (in phases)	Complete
4.	Eastern Access3 Toledo Expansion Line 9 Reversal and Expansion	US$0.2 billion $0.4 billion	US$0.2 billion $0.2 billion	2013 2013-2014 (in phases)	Complete Pre- construction
5.	Eddystone Rail Project	US$0.1 billion	No significant expenditures to date	2014	Under construction
6.	Norealis Pipeline	$0.5 billion	$0.4 billion	2014	Substantially complete
7.	Flanagan South Pipeline Project	US$2.8 billion	US$1.6 billion	2014	Under construction
8.	Canadian Mainline Expansion	$0.6 billion	$0.1 billion	2014-2015 (in phases)	Under construction
9.	Surmont Phase 2 Expansion	$0.3 billion	$0.1 billion	2014-2015 (in phases)	Under construction
10.	Athabasca Pipeline Twinning	$1.2 billion	$0.6 billion	2015	Under construction
11.	Edmonton to Hardisty Expansion	$1.8 billion	$0.2 billion	2015	Pre- construction
12.	Southern Access Extension	US$0.8 billion	US$0.1 billion	2015	Pre- construction
13.	AOC Hangingstone Lateral	$0.1 billion	No significant expenditures to date	2015	Pre- construction
14.	Sunday Creek Terminal Expansion	$0.2 billion	$0.1 billion	2015	Pre- construction
15.	Canadian Mainline System Terminal Flexibility and Connectivity	$0.6 billion	$0.2 billion	2013-2015 (in phases)	Under construction

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		Estimated Capital Cost1	Expenditures to Date2	Expected In-Service Date	Status
16.	Woodland Pipeline Extension	$0.6 billion	$0.1 billion	2015	Pre- construction
17.	JACOS Hangingstone Project	$0.1 billion	No significant expenditures to date	2016	Pre- construction
18.	Wood Buffalo Extension	$1.6 billion	No significant expenditures to date	2017	Pre- construction
19.	Norlite Pipeline System	$1.4 billion	No significant expenditures to date	2017	Pre- construction
GAS DISTRIBUTION
20.	Greater Toronto Area Project	$0.7 billion	No significant expenditures to date	2015	Pre- construction
GAS PIPELINES, PROCESSING AND ENERGY SERVICES
21.	Massif du Sud Wind Project	$0.2 billion	$0.2 billion	2013	Complete
22.	Saint Robert Bellarmin Wind Project	$0.1 billion	$0.1 billion	2013	Complete
23.	Lac Alfred Wind Project	$0.3 billion	$0.3 billion	2013 (in phases)	Complete
24.	Montana-Alberta Tie-Line	US$0.4 billion	US$0.3 billion	2013	Complete
25.	Cabin Gas Plant	$0.8 billion	$0.8 billion	To be determined	Deferred
26.	Pipestone and Sexsmith Project	$0.3 billion	$0.2 billion	2012-2014 (in phases)	Under construction
27.	Tioga Lateral Pipeline	US$0.1 billion	US$0.1 billion	2013	Complete
28.	Venice Condensate Stabilization Facility	US$0.1 billion	US$0.1 billion	2013	Complete
29.	Blackspring Ridge Wind Project	$0.3 billion	$0.2 billion	2014	Under construction
30.	Walker Ridge Gas Gathering System	US$0.4 billion	US$0.2 billion	2014-2015 (in phases)	Under construction
31.	Big Foot Oil Pipeline	US$0.2 billion	US$0.1 billion	2015	Under construction
32.	Keechi Wind Project	US$0.2 billion	No significant expenditures to date	2015	Under construction
33.	Heidelberg Lateral Pipeline	US$0.1 billion	No significant expenditures to date	2016	Pre- construction
SPONSORED INVESTMENTS
34.	EEP - Bakken Expansion Program	US$0.3 billion	US$0.3 billion	2013	Complete
35.	The Fund - Bakken Expansion Program	$0.2 billion	$0.2 billion	2013	Complete
36.	EEP - Berthold Rail Project	US$0.1 billion	US$0.1 billion	2013	Complete
37.	EEP - Ajax Cryogenic Processing Plant	US$0.2 billion	US$0.2 billion	2013	Complete
38.	EEP - Bakken Access Program	US$0.1 billion	US$0.1 billion	2013	Complete
39.	EEP - Texas Express NGL System	US$0.4 billion	US$0.4 billion	2013	Complete
40.	EEP - Line 6B 75-Mile Replacement Program	US$0.4 billion	US$0.4 billion	2013-2014 (in phases)	Under construction

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		Estimated Capital Cost1	Expenditures to Date2	Expected In-Service Date	Status
41.	EEP - Eastern Access4	US$2.6 billion	US$1.3 billion	2013-2016 (in phases)	Under construction
42.	EEP - Lakehead System Mainline Expansion4	US$2.4 billion	US$0.2 billion	2014-2016 (in phases)	Under construction
43.	EEP - Beckville Cryogenic Processing Facility	US$0.1 billion	No significant expenditures to date	2015	Pre- construction
44.	EEP - Sandpiper Project	US$2.6 billion	US$0.1 billion	2016	Pre- construction

1These 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.

2Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2013.

3See Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access for project discussion.

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

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

LIQUIDS PIPELINES

Seaway Crude Pipeline System

Acquisition of Interest

In 2011, Enbridge acquired a 50% interest in the Seaway Pipeline at a cost of approximately US$1.2 billion. Seaway Pipeline includes the 805-kilometre (500-mile) 30-inch diameter long-haul system from Freeport, Texas to Cushing, Oklahoma.

Reversal and Expansion

The flow direction of the Seaway Pipeline was reversed, enabling it to transport crude oil from the oversupplied hub in Cushing, Oklahoma to the Gulf Coast. The initial reversal of the pipeline and preliminary service commenced in 2012, providing initial capacity of 150,000 bpd. Further pump station additions and modifications were completed in January 2013, increasing capacity available to shippers to up to approximately 400,000 bpd, depending on crude oil slate. Actual throughput experienced in 2013 was curtailed due to constraints on third party takeaway facilities. A 105-kilometre (65-mile), 36-inch diameter pipeline lateral from the Seaway Jones Creek facility to Enterprise Product Partners L.P.’s (Enterprise) ECHO crude oil terminal (ECHO Terminal) in Houston, Texas was placed into service in January 2014 and is expected to relieve these constraints.

Twinning and Extension

Based on additional capacity commitments from shippers, a second line is being constructed that is expected to more than double the existing capacity of the Seaway Pipeline to 850,000 bpd by mid-2014. This 30-inch diameter pipeline will follow the same route as the existing Seaway Pipeline. Included in the project scope is the lateral from the Seaway Jones Creek facility southwest of Houston, Texas into the ECHO Terminal noted above.

In addition, a 137-kilometre (85-mile) pipeline will be 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 will provide capacity of 750,000 bpd and is now expected to be available in mid-2014.

Including the acquisition of the initial 50% interest, Enbridge’s total expected cost for the Seaway Pipeline is approximately US$2.4 billion. The acquisition, reversal and expansion are expected to cost US$1.3 billion, with the twinning, extension and lateral to the ECHO Terminal components of the project expected to cost approximately US$1.1 billion. Total expenditures incurred to date are approximately US$1.8 billion.

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Suncor Bitumen Blend

Under an agreement with Suncor Energy Oil Sands Limited Partnership (Suncor Partnership), the Suncor Bitumen Blend project involved the construction of a new 350,000 barrel tank, new blend and diluent lines and pumping capacity to connect with Suncor Partnership’s lines just outside Enbridge’s Athabasca Tank Farm. Enbridge completed construction of the new facilities in June 2013, which enables Suncor Partnership to transport blended bitumen volumes from its Firebag production into the Wood Buffalo Pipeline. The project was completed at an approximate cost of $0.2 billion.

South Cheecham Rail and Truck Terminal

The Company partnered with Keyera Corp. (Keyera) to construct the initial phase of the South Cheecham Rail and Truck Terminal (the Terminal), located approximately 75 kilometres (47 miles) southeast of Fort McMurray, Alberta. The Terminal, which is being developed in phases, will be a multi-purpose hydrocarbon rail and truck terminal, designed to support bitumen producers within the Athabasca oil sands area and facilitate product moving in and out of the region. In addition to the facilities for handling diluent and diluted bitumen at the Terminal, the initial phase includes both a diluent and a diluted bitumen pipeline connection to Statoil Canada Limited’s Cheecham Terminal which could be connected to Enbridge’s existing Cheecham Terminal in the future. Construction of the first phase was completed and placed into service in October 2013 with post-completion expenditures expected to be incurred into 2014. The cost of the first phase is expected to be approximately $90 million and Enbridge’s share of the project costs will be based upon its 50% joint venture interest. Construction of additional phases of the Terminal is under active consideration by the Company and Keyera.

Athabasca Pipeline Capacity Expansion

In December 2013, the Company completed the second phase of the expansion of its Athabasca Pipeline to its full capacity of approximately 570,000 bpd, depending on the mix of crude oil types. The first phase of the expansion, which increased capacity to approximately 430,000 bpd, was completed and placed into service in March 2013. The Athabasca Pipeline transports crude oil from various oil sands projects to the mainline hub at Hardisty, Alberta. The completed expansion will accommodate additional contractual commitments, including incremental production from the Christina Lake Oil Sands Project operated by Cenovus Energy Inc. (Cenovus). The total cost of the project was approximately $0.4 billion.

Eddystone Rail Project

The Company entered into a joint venture agreement with Canopy Prospecting Inc. to develop 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. The Eddystone Rail Project includes leasing portions of a power generation facility and reconfiguring existing track to accommodate 120-car unit-trains, installing crude oil offloading equipment, refurbishing an existing 200,000 barrel tank and upgrading an existing barge loading facility. The project is expected to be placed into service in the first quarter of 2014 and will receive and deliver an initial capacity of 80,000 bpd, expandable to 160,000 bpd. The total estimated cost of the project is approximately US$0.1 billion and Enbridge’s share of the project costs will be based upon its 75% joint venture interest.

Norealis Pipeline

In order to provide pipeline and terminalling services to the proposed Husky Energy Inc. operated Sunrise Energy Project, the Company is undertaking construction of 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 estimated cost of the project is approximately $0.5 billion, with expenditures to date of approximately $0.4 billion. The terminal scope of work was substantially completed in December 2013 and the overall system is expected to be available for service in the first quarter of 2014.

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Flanagan South Pipeline Project

The 950-kilometre (590-mile) Flanagan South Pipeline will have an initial capacity of approximately 600,000 bpd to transport crude oil from the Company’s terminal at Flanagan, Illinois to Cushing, Oklahoma. The 36-inch diameter pipeline is being installed adjacent to the Company’s Spearhead Pipeline for the majority of the route. Subject to regulatory and other approvals, the pipeline is expected to be in service in the third quarter of 2014. The estimated cost of the project is approximately US$2.8 billion, with expenditures to date of approximately US$1.6 billion.

On August 23, 2013, the Sierra Club and National Wildlife Federation (the Plaintiff) filed a complaint for Declaratory and Injunctive Relief (the Complaint) with the United States District Court for the District of Columbia (the Court). 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 National Environmental Protection Act. On September 5, 2013, Enbridge obtained intervener status and joined the Defendants in filing a response in opposition to the motion for preliminary injunction. The Court hearing was held on September 27, 2013 and the Plaintiff’s request for preliminary injunction was denied by the Court on November 13, 2013. A court hearing is scheduled for February 21, 2014 concerning the merits of the Complaint against the federal agencies.

Canadian Mainline Expansion

Enbridge is undertaking an estimated $0.2 billion expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba. The scope of the project involves the addition of pumping horsepower sufficient to raise the capacity of the Alberta Clipper line by 120,000 bpd to a capacity of 570,000 bpd and is expected to be in service in the third quarter of 2014.

In January 2013, Enbridge announced a further expansion of the Canadian Mainline system between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba, at an estimated cost of $0.4 billion. Subject to National Energy Board (NEB) approval, the scope of the additional expansion involves the addition of pumping horsepower sufficient to raise the capacity of the Alberta Clipper line by another 230,000 bpd to its full capacity of 800,000 bpd and is expected to be in service in 2015.

The total estimated cost for the Canadian Mainline Expansion is $0.6 billion, with expenditures to date of approximately $0.1 billion. Delays in receipt of the applicable regulatory approvals on EEP’s portion of the mainline system expansion are expected to affect the Canadian Mainline Expansion. However, temporary system optimization actions are being undertaken to substantially mitigate any impact on throughput from the delay. See Growth Projects — Commercially Secured Projects — Sponsored Investments — Enbridge Energy Partners, L.P. — Lakehead System Mainline Expansion.

Surmont Phase 2 Expansion

In May 2013, the Company announced it had entered into a terminal services agreement with ConocoPhillips Canada Resources Corp. (ConocoPhillips) and Total E&P Canada Ltd. (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 expected to come into service in two phases, with the blended product system expected in the fourth quarter of 2014 and the diluent system expected in the first quarter of 2015. The estimated cost of the project is approximately $0.3 billion with expenditures to date of approximately $0.1 billion.

Athabasca Pipeline Twinning

This project involves the twinning of the southern section of the Company’s 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 of $0.6 billion, will include 346 kilometres (215 miles) of 36-inch pipeline adjacent to the existing Athabasca Pipeline right-of-way. The initial annual capacity of the pipeline will be approximately 450,000 bpd, with expansion potential to 800,000 bpd. Subject to regulatory and other approvals, the line is expected to enter service in 2015.

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Edmonton to Hardisty Expansion

The Company is undertaking an expansion of the Canadian Mainline system between Edmonton, Alberta and Hardisty, Alberta. The expansion project, with an estimated cost of approximately $1.8 billion, and expenditures incurred to date of approximately $0.2 billion, will include 181 kilometres (112 miles) of new 36-inch diameter pipeline, expected to generally follow the same route as Enbridge’s existing Line 4 pipeline, and new terminal facilities in Edmonton which include five new 500,000 barrel tanks and connections into existing infrastructure at Hardisty Terminal. The initial capacity of the new line will be approximately 570,000 bpd, with expansion potential to 800,000 bpd and is expected to be placed into service in 2015.

Southern Access Extension

The Southern Access Extension project will consist of the construction of a new 265-kilometre (165-mile) 24-inch diameter crude oil pipeline from Flanagan, Illinois to Patoka, Illinois as well as additional tankage and two new pump stations. Subject to regulatory and other approvals, the project is expected to be placed into service in 2015 at an approximate cost of US$0.8 billion, with expenditures to date of approximately US$0.1 billion. The initial capacity of the new line is expected to be approximately 300,000 bpd. Prior to the binding open season that closed in January 2013, Enbridge had received sufficient capacity commitments from an anchor shipper to support the 24-inch pipeline. In June 2013, a second open season to solicit additional capacity commitments from shippers was announced and subsequently closed in September 2013. The Company received a further capacity commitment through the second open season, which can be accommodated within the initial capacity planned for the pipeline.

AOC Hangingstone Lateral

In March 2013, the Company announced that it 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 2015 at an estimated cost of approximately $0.1 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.

Sunday Creek Terminal Expansion

In January 2014, the Company announced it will construct additional facilities at its Sunday Creek Terminal, located in the Christina Lake area of northern Alberta, to support production growth from the Christina Lake oil sands operated by Cenovus 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 work for a future tank. The existing Sunday Creek Terminal was put into service in August 2011. The estimated cost for the expansion is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion and a targeted in-service date of 2015.

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 cost of the project is expected to be approximately $0.6 billion, with expenditures incurred to date of approximately $0.2 billion, and with varying completion dates from 2013 through 2015 related to existing terminal facility modifications. These modifications are comprised of upgrading existing booster pumps, additional booster pumps and new tank line connections.

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Woodland Pipeline Extension

In July 2013, Enbridge announced that it had received shipper sanctioning for the Woodland Pipeline Extension Project. The joint venture project will extend the Woodland Pipeline south from Enbridge’s Cheecham Terminal to its Edmonton Terminal. The extension is a proposed 385-kilometre (228-mile), 36-inch diameter pipeline with an initial capacity of 400,000 bpd, expandable to 800,000 bpd. Enbridge’s share of the estimated capital cost of the project is approximately $0.6 billion, with expenditures incurred to date of approximately $0.1 billion. Subject to finalization of scope and a definitive cost estimate, the project has a target in-service date of 2015.

JACOS Hangingstone Project

In September 2013, Enbridge announced it will construct 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 approval, Enbridge plans to construct a new 50-kilometre (31-mile) 12-inch lateral pipeline to connect the JACOS Hangingstone project site to Enbridge’s existing Cheecham Terminal. The project will provide capacity of 40,000 bpd at an estimated cost of approximately $0.1 billion and is expected to enter service in 2016.

Wood Buffalo Extension

In October 2013, Enbridge announced that it was selected by Suncor Energy Inc., Total E&P Canada Ltd. and Teck Resources Limited (the Fort Hills Partners), as well as the 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 include the 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.

Norlite Pipeline System

In October 2013, Enbridge announced it will develop Norlite, a new industry diluent pipeline to meet the needs of multiple producers in the Athabasca oil sands region. Under the currently envisioned scope, a 20-inch diameter pipeline with an approximate ultimate capacity of up to 280,000 bpd, depending on final scope and hydraulic design, 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 489-kilometre (303-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. If Enbridge is successful in securing additional long term commitments on the proposed Norlite system, the scope of the project could be increased to a 24-inch diameter pipeline system as well as include a potential lateral pipeline to Enbridge’s Norealis Terminal. Subject to regulatory and other approvals, Norlite is expected to be completed in 2017 at an estimated cost of approximately $1.4 billion. If upsized to a 24-inch diameter pipeline, it will provide capacity to transport up to 270,000 bpd of diluent from Edmonton into the Athabasca oil sands region, with the potential to be further expanded to approximately 400,000 bpd of capacity with the addition of pump stations. Norlite has the right to access certain existing capacity on Keyera pipelines between Edmonton and Stonefell and, in exchange, Keyera may elect to participate in the new pipeline infrastructure as a 30% non-operating owner.

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GAS DISTRIBUTION Greater Toronto Area Project EGD plans to expand its natural gas distribution system in the Greater Toronto Area (GTA) to meet the demands of growth and to continue the safe and reliable delivery of natural gas to current and future customers. At an expected cost of approximately $0.7 billion, the proposed GTA project will consist of two segments of pipeline and related facilities to upgrade the existing distribution system that delivers natural gas to several municipalities in Ontario. The Company filed amended applications reflecting scope modifications with the Ontario Energy Board (OEB) in February, April and July 2013. As a result of the July scope modification, the expected capital cost increased by approximately $0.1 billion. OEB hearings were held in September and October 2013 and approval was received from the OEB in January 2014. Construction is targeted to start in late 2014, with completion expected by the end of 2015.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Massif du Sud Wind Project

Enbridge secured a 50% interest in the development of the 150-MW Massif du Sud Wind Project (Massif du Sud), located 100 kilometres (60 miles) east of Quebec City, Quebec. Massif du Sud delivers energy to Hydro-Quebec under a 20-year PPA. Project construction was completed in December 2012 at a final investment by Enbridge of approximately $0.2 billion and commercial operation commenced in January 2013.

Saint Robert Bellarmin Wind Project

In July 2013, Enbridge acquired a 50% interest in the 80-MW Saint Robert Bellarmin Wind Project, located 300 kilometres (185 miles) east of Montreal, Quebec. The project is operational and power output is being delivered to Hydro-Quebec under a 20-year PPA. The Company’s total investment in the project was approximately $0.1 billion.

Lac Alfred Wind Project

Enbridge secured a 50% interest in the development of the 300-MW Lac Alfred Wind Project (Lac Alfred), located 400 kilometres (250 miles) northeast of Quebec City in Quebec’s Bas-Saint-Laurent region. Lac Alfred delivers energy to Hydro-Quebec under a 20-year PPA. The project was constructed under a fixed price, turnkey, engineering, procurement and construction agreement. Construction was completed during 2013 and commercial operations commenced in two phases: Phase 1 in January 2013 and Phase 2 in August 2013, with each phase providing 150-MW of generation capacity. The Company’s total investment in the project was approximately $0.3 billion.

Montana-Alberta Tie-Line

In September 2013, Enbridge completed and placed into service the first 300-MW phase of MATL. MATL is a 345-kilometre (215-mile) transmission line from Great Falls, Montana to Lethbridge, Alberta, designed to take advantage of the growing supply of electric power in Montana and buoyant power demand in Alberta. Post-completion expenditures will continue to be incurred into 2014 and the estimated cost for the first phase of the project remains at approximately US$0.4 billion, with expenditures to date of approximately US$0.3 billion. An expansion of an additional 300-MW of transmission capacity is under active consideration and an in-service date and definitive cost estimate are dependent on finalization of scope, regulatory approval and customer support.

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Cabin Gas Plant

In 2011, the Company secured a 71% interest in the development of the Cabin Gas Plant (Cabin), located 60 kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin. The Company’s total investment in phases 1 and 2 of Cabin was expected to be approximately $1.1 billion. In October 2012, the Company and its partners announced plans to defer both the commissioning of phase 1 and the construction of phase 2. Expenditures were incurred throughout 2013 to complete pre-commissioning construction on Phase 1 and to place Phase 2 into preservation mode. Under the deferral, the Company’s total investment in phases 1 and 2 is approximately $0.8 billion. In December 2012, Enbridge started earning fees on its investment made to date in both phases 1 and 2. On May 1, 2013, the Company became operator of Cabin.

Pipestone and Sexsmith Project

In 2012, the Company acquired from Encana Corporation (Encana) certain sour gas gathering and compression facilities located in the Peace River Arch (PRA) region of northwest Alberta (collectively, Pipestone and Sexsmith). These facilities were either in service (Sexsmith) or under construction (Pipestone).  Construction of new gathering lines and NGL handling facilities are being completed in phases with final completion expected in the second quarter of 2014. Enbridge’s investment in Pipestone and Sexsmith is expected to be approximately $0.3 billion, with expenditures to date of approximately $0.2 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. Financial terms of Pipestone and Sexsmith are substantially consistent with previously established terms of the Cabin development.

Tioga Lateral Pipeline

In September 2013, Alliance Pipeline US completed construction and placed into-service a natural gas pipeline lateral and associated facilities to connect production from the Hess Corporation (Hess) Tioga field processing plant in the Bakken region of North Dakota to the Alliance mainline near Sherwood, North Dakota. The 127-kilometre (79-mile) Tioga Lateral Pipeline will facilitate movement of liquids-rich natural gas to NGL processing facilities owned by Aux Sable near the terminus of Alliance. The pipeline has an initial design capacity of approximately 126 million cubic feet per day (mmcf/d), which can be expanded based on shipper demand. Through its 50% ownership interest in Alliance Pipeline US, Enbridge’s share of the final cost of the project was approximately US$0.1 billion. In October 2012, Alliance Pipeline US executed a contract with Hess as an anchor shipper. Aux Sable and Hess reached a concurrent agreement for provision of NGL services.

Venice Condensate Stabilization Facility

In November 2013, the Company completed the expansion of the Venice Condensate Stabilization and Separation Facilities (Venice) at its Venice, Louisiana facility within Enbridge Offshore Pipelines (Offshore). The expansion increased the capacity of the stabilization facilities to approximately 12,500 barrels of condensate per day and the separation facilities to approximately 12,200 bpd. The project was completed at an approximate cost of US$0.1 billion. The expanded condensate stabilizing capacity is required to accommodate additional natural gas production from the Olympus offshore oil and gas development. Natural gas production from Olympus will move to Enbridge’s onshore facility at Venice via Enbridge’s Mississippi Canyon offshore pipeline system, where the condensate will be separated from the gas and stabilized.

Blackspring Ridge Wind Project

In April 2013, the Company announced that it had secured a 50% interest in the development of the 300-MW Blackspring Ridge project, located 50 kilometres (31 miles) north of Lethbridge, Alberta in Vulcan County. The project is being constructed under a fixed price engineering, procurement and construction contract and is expected to be completed in the second quarter of 2014. Renewable Energy Credits generated from Blackspring Ridge are contracted to Pacific Gas and Electric Company under a 20-year purchase agreement. The electricity will be sold into the Alberta power pool with pricing fixed on 75% of production through long-term contracts. The Company’s total investment in the project is expected to be approximately $0.3 billion, with expenditures incurred to date of approximately $0.2 billion.

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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 meters (7,000 feet) with capacity of 100 mmcf/d. The Jack St. Malo portion of the WRGGS is expected to be placed into service in the third quarter of 2014 and the Big Foot Pipeline portion is now expected to be placed into service in the second quarter of 2015. The total WRGGS project is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.2 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$0.1 billion, and is now expected to enter service in the second quarter of 2015 to align with the availability of production.

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 project, located in Jack County, Texas, at an investment of approximately US$0.2 billion. RES Americas is constructing the wind project under a fixed price, engineering, procurement and construction agreement. Construction on the project commenced in December 2013, with expected completion in 2015. Upon attaining commercial operation, MetLife, Inc. will provide tax equity financing for the project. 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.

Heidelberg Lateral 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 (Anadarko), to an existing third-party system. Heidelberg, a 20-inch 58-kilometre (36-mile) pipeline, 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 is expected to be operational by 2016 at an approximate cost of US$0.1 billion.

SPONSORED INVESTMENTS

Bakken Expansion Program

A joint project to further expand crude oil pipeline capacity to accommodate growing crude oil production from the Bakken and Three Forks formations located in North Dakota was undertaken by EEP and the Fund. The project, undertaken by EEP in the United States and the Fund in Canada, reversed and expanded an existing pipeline, running from Berthold, North Dakota, to Steelman, Saskatchewan, and constructed a new 16-inch pipeline from a new terminal near Steelman to the Enbridge mainline terminal near Cromer, Manitoba. The project was completed and entered service in March 2013, providing capacity of 145,000 bpd. The United States portion of the project was completed at an approximate cost of US$0.3 billion and the Canadian portion of the project was completed at an approximate cost of $0.2 billion.

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Enbridge Energy Partners, L.P.

Berthold Rail Project

The Berthold Rail project expanded capacity into the Berthold Terminal in North Dakota by 80,000 bpd and involved the construction of a three-unit-train loading facility, crude oil tankage and other terminal facilities adjacent to existing infrastructure. The first phase of terminal facilities was completed in 2012, providing additional capacity of 10,000 bpd to the Berthold Terminal. The loading facility and crude oil tankage were subsequently completed and placed into service in March 2013. The total cost of the project was approximately US$0.1 billion.

Ajax Cryogenic Processing Plant

In September 2013, EEP placed into service the Ajax Plant, comprised of a newly constructed natural gas processing plant and related facilities, on its Anadarko System. The Ajax Plant provides capacity of 150 mmcf/d and, in conjunction with the Allison Plant, has increased total processing capacity on the Anadarko System to approximately 1,150 mmcf/d. The Anadarko System’s condensate stabilization capacity was also increased by approximately 2,000 bpd. With the Texas Express NGL System completed in October 2013 as discussed below, the Ajax Plant is capable of producing approximately 15,000 bpd of NGL. The total cost of the Ajax Plant project was approximately US$0.2 billion.

Bakken Access Program

The Bakken Access Program represents an upstream expansion that will further complement EEP’s Bakken expansion. The Bakken Access Program was placed into service in phases in the middle of 2013 and enhanced crude oil gathering capabilities on the North Dakota System by 100,000 bpd. The program involved increasing pipeline capacity, constructing additional storage tanks and adding truck access facilities at multiple locations in western North Dakota at an approximate cost of US$0.1 billion.

Texas Express NGL System

In October 2013, EEP, Enterprise, Anadarko and DCP Midstream Partners, L.P. (DCP Midstream) announced that the Texas Express NGL System was placed into service. The Texas Express NGL System is a joint venture that was created to design and construct a new NGL pipeline and NGL gathering system. The NGL pipeline is a joint venture between EEP, Enterprise, Anadarko and DCP Midstream and the NGL gathering system is a joint venture between EEP, Enterprise and Anadarko. Enterprise constructed and operates the NGL pipeline, while EEP constructed and operates the NGL gathering system. EEP’s total investment in the Texas Express NGL System was approximately US$0.4 billion.

The Texas Express NGL System originates in Skellytown, Texas and extends approximately 935 kilometres (580 miles) to NGL fractionation and storage facilities in Mont Belvieu, Texas. The Texas Express NGL System has an initial capacity of approximately 280,000 bpd, expandable to approximately 400,000 bpd. Approximately 250,000 bpd of capacity has been subscribed on the pipeline. The new NGL gathering system consists of approximately 187 kilometres (116 miles) of gathering lines that connect the Texas Express NGL System to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma, as well as to the central Texas Barnett Shale processing plants.

Line 6B 75-Mile Replacement Program

This program includes 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 are being completed in components, with approximately 104 kilometres (65 miles) of segments placed in service since the first quarter of 2013. The two remaining 8-kilometre (5-mile) segments in Indiana are expected to be placed in service in the first quarter of 2014. The total estimated capital for this replacement program is approximately US$0.4 billion, with expenditures to date of approximately US$0.4 billion. EEP will recover 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 Enbridge include a reversal of its Line 9 and expansion of the Toledo Pipeline. 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. The individual projects are further described below.

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In August 2013, Enbridge completed the reversal of a portion of its Line 9A in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario. Enbridge also plans to undertake a full reversal of its 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in Quebec. The Line 9B reversal is expected to be completed at an estimated cost of approximately $0.3 billion, including estimated costs associated with integrity digs being performed on the line. 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 9B capacity expansion project. The Line 9B capacity expansion will increase the annual capacity of Line 9B from 240,000 bpd to 300,000 bpd at an estimated cost of approximately $0.1 billion. Subject to NEB approval, the Line 9B reversal and Line 9B capacity expansion are expected to be available for service in the fourth quarter of 2014 at a total estimated cost of approximately $0.4 billion. Expenditures incurred to date for the Lines 9A and 9B projects are approximately $0.2 billion.

In May 2013, Enbridge completed an 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.

Both the Toledo Pipeline and Line 9 assets are included in the Company’s Liquids Pipelines segment.

In May 2013, EEP completed and placed into service the expansion of its Line 5 light crude oil line between Superior, Wisconsin and Sarnia, Ontario. The Line 5 expansion increased capacity by 50,000 bpd at an approximate cost of US$0.1 billion.

In November 2013, EEP completed and placed into service the expansion of its Line 62 between Flanagan, Illinois and Griffith, Indiana. The Line 62 expansion increased capacity by 105,000 bpd. EEP is also replacing additional sections of Line 6B in Indiana and Michigan, including 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 are being replaced with 36-inch diameter pipe. The target in-service date for the Line 6B project is split into two phases, with the segment between Griffith and Stockbridge expected to be completed in the first quarter of 2014 and the segment from Ortonville, Michigan to Sarnia, Ontario expected to be completed in the third quarter of 2014. The replacement of the Line 6B sections is in addition to the Line 6B Replacement Program discussed previously. The expected cost of the United States mainline expansions is approximately US$2.2 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 involve the addition of new pumps, existing station modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. The project is expected to be placed into service in 2016 at an estimated capital cost of approximately US$0.4 billion.

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$2.6 billion, with expenditures to date of approximately US$1.3 billion. The Eastern Access projects, excluding the Toledo Expansion and Line 9 Reversal and Expansion, are now being funded 75% by Enbridge and 25% by EEP, after EEP exercised the option to reduce its funding and associated economic interest in the project by 15% on June 28, 2013. 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 15%. For further discussion refer to Liquidity and Capital Resources.

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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 includes the expansion of Alberta Clipper (Line 67) and Southern Access (Line 61).

The current scope of the Alberta Clipper expansion between the border and Superior, Wisconsin consists of two phases. The initial phase includes an increase in capacity from 450,000 bpd to 570,000 bpd at an estimated capital cost of approximately US$0.2 billion. In January 2013, EEP announced a further expansion of the Lakehead System mainline between the border and Superior to 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 target in-service dates for the proposed projects are the third quarter of 2014 for the initial phase and 2015 for the second phase. It is now anticipated that it will take longer to obtain regulatory approval than planned. A number of temporary system optimization actions are being undertaken to substantially mitigate any impact on throughput.

The current scope of the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois also consists of two phases. The initial phase includes an increase in capacity from 400,000 bpd to 560,000 bpd 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 at an estimated capital cost of approximately US$1.3 billion. Both phases of the expansion would require only the addition of pumping horsepower and crude oil tanks at existing sites with no pipeline construction. The target in-service date for the first phase of the expansion is expected to be in the third quarter of 2014. For the second phase of the expansion, which remains subject to regulatory and other approvals, the pump station expansion is expected to be available for service in 2015, with additional tankage requirements expected to be completed in 2016.

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 122-kilometre (76-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 2015.

The projects collectively referred to as the Lakehead System Mainline Expansion are expected to cost approximately US$2.4 billion, with expenditures incurred to date of approximately US$0.2 billion. EEP will operate the project on a cost-of-service basis. The Lakehead System Mainline Expansion is now being funded 75% by Enbridge and 25% by EEP, after EEP exercised the option to reduce its funding and associated economic interest in the project by 15% on June 28, 2013. 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 15%. For further discussion refer to Liquidity and Capital Resources.

Beckville Cryogenic Processing Facility

In April 2013, EEP announced plans to construct a cryogenic natural gas processing plant near Beckville (the Beckville Plant) in Panola County, Texas, at an expected cost of approximately US$0.1 billion. The Beckville Plant will offer incremental processing capacity for existing and future customers in the 10-county Cotton Valley shale region, where EEP’s 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. Construction activities have commenced and the Beckville Plant is expected to be placed into service in 2015.

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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 original proposed expansion would involve construction of a 965-kilometre (600-mile) 24-inch diameter line from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line will twin the 210,000 bpd North Dakota System mainline, which now terminates at Clearbrook Terminal in Minnesota, adding 225,000 bpd of capacity on the twin line between Tioga and Clearbrook and 375,000 bpd of capacity between Clearbrook and Superior. In September 2013, a scope modification was made to increase the twin line diameter from 24-inches to 30-inches between Clearbrook and Superior. As a result of the September 2013 scope modification, the expected capital cost increased by approximately US$0.1 billion and Sandpiper is now expected to cost approximately US$2.6 billion, with expenditures incurred to date of approximately US$0.1 billion.

In November 2013, EEP and Enbridge announced that Marathon Petroleum Corporation (MPC) had 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 has the option to participate in other growth projects (not to exceed $1.2 billion in aggregate). As a result of Williston 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 early 2016.

A petition was filed with the Federal Energy Regulatory Commission (FERC) to approve recovery of Sandpiper’s costs through a surcharge to the Enbridge Pipelines (North Dakota) LLC rates between Beaver Lodge and Clearbrook and a cost of service structure for rates between Clearbrook and Superior. On March 22, 2013, the FERC denied the petition on procedural grounds. EEP plans to re-file its petition with modifications to address the FERC’s concerns. Furthermore, in November 2013, EEP announced 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. The pipeline is expected to begin service in early 2016, subject to obtaining regulatory and other approvals, as well as finalization of scope.

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 which 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

Eastern Gulf Crude Access Pipeline

The memorandum of understanding (MOU) between the Company and Energy Transfer Partners, L.P. has expired and the Company no longer has the right to acquire an interest in the Eastern Gulf Crude Access Pipeline. The proposed project would have provided access to the eastern Gulf Coast refinery market from the Patoka, Illinois hub. The MOU expired without satisfaction of its condition with respect to throughput commitments and FERC approval of conversion from natural gas service to crude oil of certain segments of pipeline that are currently in operation. The Company believes there is demand for transportation service from the United States midwest to the eastern Gulf Coast refinery market and will continue to assess future opportunities to meet potential shipper needs, including a revised Eastern Gulf Crude Access Pipeline joint venture.

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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. The JRP found that the potential economic effects of Northern Gateway on local, regional, and national economics would be positive and would likely be significant. The JRP is also of the view that the Company’s commitments break new ground by providing an unprecedented level of long-term economic, environmental, and social benefits to Aboriginal groups. It 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 found that Northern Gateway provided appropriate and effective opportunities for the public and potentially-affected parties to learn about the project, and to provide their views and concerns to the Company. The JRP was satisfied that Northern Gateway considered, and was responsive to, the input it received regarding the design, construction, and operation of the project.

The JRP found Northern Gateway applied a careful and precautionary approach to its environmental assessment and that Northern Gateway had presented a level of engineering design information that met, or exceeded, regulatory requirements for a thorough and comprehensive review in terms of whether or not it can construct and operate the project in a safe and responsible manner that protects people and the environment. The JRP found that Northern Gateway followed good engineering practice in determining a route that avoids or minimizes exposure to geohazards, had taken all reasonable steps to design a project that would minimize risks of project malfunctions and accidents due to naturally occurring events and that mandatory and voluntary measures outlined by the Company would reduce the potential for human error to the greatest extent possible.

The JRP also referenced the conclusions of the TERMPOL committee and the evidence of various expert witnesses appearing on behalf of Northern Gateway and the Government of Canada in its assessment of the safety of marine transport and concluded that shipping along the north coast of British Columbia could be accomplished safely the vast majority of the time even in the absence of many of the mitigation measures that would be in place for Northern Gateway. These additional mitigation measures would include reduced vessel speeds, escort tugs, redundant navigational systems and avoiding congestion in the narrower parts of the shipping channels. The JRP noted Northern Gateway’s commitments represent a substantial increase in spill response capabilities beyond those required by existing legislation and currently existing on the west coast of British Columbia, that they are based on international best practice and continual advances in technology and spill response planning.

The JRP included an appendix with 209 conditions that the JRP recommended be included in any certificate that was issued.

The JRP recommended to the Governor in Council that certificates of public convenience and necessity 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 will now consult with Aboriginal groups on the JRP report and its recommendations prior to making a decision on whether to direct the NEB to issue the certificates for the pipelines. Of the 45 Aboriginal groups eligible to participate as equity owners, 26 have signed up to do so. The Governor in Council’s decision is expected in June 2014.

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The cost estimate included in the Northern Gateway filing with the JRP reflects a preliminary estimate prepared in 2004 and escalated to 2010. A detailed estimate based on full engineering analysis of the pipeline route and terminal location is currently being prepared. The detailed estimate will reflect a larger proportion of high cost terrain, longer tunnelling requirements and more extensive terminal site rock excavation than provided for in the preliminary estimate, which is expected to result in a significant increase in the cost estimate. The revised estimate is anticipated to be completed in the first quarter of 2014.

Five applications for judicial review have been filed with the Federal Court and the Federal Court of Appeal; three from Aboriginal groups and two from environmental groups. The applications seek to set aside the findings of the JRP and prohibit the Federal Government from taking any action to enable the project to proceed.

Subject to continued commercial support, regulatory and other approvals and adequately addressing landowner and local community concerns (including those of Aboriginal communities), the Company currently estimates that Northern Gateway could be in service in 2018 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.

Expenditures to date, which relate primarily to the regulatory process, are approximately $0.4 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. None of the information contained on, or connected to, the JRP website or the Northern Gateway website is incorporated 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 MOU to jointly develop the NEXUS Gas Transmission System (NEXUS), 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 proposed NEXUS project would originate in northeastern Ohio, include approximately 400 kilometres (250 miles) of large diameter pipe, and be capable of transporting one billion cubic feet per day (bcf/d) of natural gas. The line would follow existing utility corridors to an interconnect in Michigan and utilize the existing Vector pipeline to reach the Ontario market. Upon completion, Spectra would become a 20% owner in Vector, a joint venture between DTE and Enbridge. The partners continue to monitor Utica shale development progress, awaiting increased interest by producers in accessing the Ohio/Michigan/Ontario market.

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LIQUIDS PIPELINES

EARNINGS

	2013		2012		2011
(millions of Canadian dollars)
Canadian Mainline	460		432		336
Regional Oil Sands System	170		110		111
Southern Lights Pipeline	49		42		41
Seaway Pipeline	48		24		(3	)
Spearhead Pipeline	31		37		17
Feeder Pipelines and Other	12		10		(1	)
Adjusted earnings	770		655		501
Canadian Mainline - changes in unrealized derivative fair value gains/(loss)	(268	)	42		(48	)
Canadian Mainline - Line 9 tolling adjustment	-		6		10
Canadian Mainline - shipper dispute settlement	-		-		14
Regional Oil Sands System - leak remediation and long-term pipeline stabilization costs	(56	)	-		-
Regional Oil Sands System - make-up rights adjustment	(13	)	-		-
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	)	-
Regional Oil Sands System - asset impairment write-off	-		-		(8	)
Spearhead Pipeline - changes in unrealized derivative fair value gains	-		-		1
Earnings attributable to common shareholders	427		697		470

Liquids Pipelines adjusted earnings were $770 million in 2013 compared with adjusted earnings of $655 million in 2012 and $501 million in 2011. The Company continued to realize growth on Canadian Mainline primarily from strong supply from western Canada and the ongoing effect of crude oil price differentials whereby demand for discounted crude by United States midwest refiners remained high and drove increases in throughput on the Canadian Mainline. New assets placed into service on Regional Oil Sands System and expanded available capacity on Seaway Pipeline 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 2012 and 2011 included a Line 9 tolling adjustment related to services provided in prior periods.

·Canadian Mainline earnings for 2011 included the settlement of a shipper dispute related to oil measurement adjustments in prior years.

·Regional Oil Sands System earnings for 2013 included a charge related to the Line 37 crude oil release which occurred in June 2013. See Liquids Pipelines – Regional Oil Sands System – Line 37 Crude Oil Release.

·Regional Oil Sands System earnings for 2013 included an adjustment to recognize revenue for certain long-term take-or-pay contracts ratably over the contract life. Make-up rights are earned 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. As such, adjusted earnings reflect contributions from these contracts ratably over the life of the contract, consistent with contractual cash payments under the contract.

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·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.

·Regional Oil Sands System earnings for 2011 included the write-off of development expenditures on certain project assets.

·Spearhead Pipeline earnings for 2011 included unrealized fair value gains on derivative financial instruments used to manage exposures to allowance oil commodity prices.

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 2.5 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 International Joint Tariff (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. 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.

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Incentive Tolling

Prior to the CTS taking effect on July 1, 2011, tolls on Canadian Mainline were governed by various agreements which were subject to NEB approval. These agreements included both the 2011 and 2010 ITS applicable to the Canadian Mainline (excluding Lines 8 and 9), the Terrace agreement, the SEP II Risk Sharing agreement, the Alberta Clipper agreement and the Southern Access Expansion agreement which were recovered via the Mainline Expansion Toll.

Results of Operations

Canadian Mainline adjusted earnings were $460 million for the year ended December 31, 2013 compared with $432 million for the year ended December 31, 2012 and $336 million for the year ended December 31, 2011. The adjusted earnings increase was primarily driven by higher throughput from steady production from the oil sands in Alberta priced at levels which 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. The tempered growth in demand from refineries is expected to persist during the first quarter of 2014.

Partially offsetting increased throughput in 2013 was a lower Canadian Mainline IJT Residual Benchmark Toll effective April 1, 2013 compared with the corresponding 2012 period. Changes in the Canadian Mainline IJT Residual Benchmark Toll are inversely correlated to the Lakehead System Local Toll which was higher due to increased costs in relation to EEP’s growth projects which will be recovered through the Lakehead System’s rate structure. 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.

The comparability of Canadian Mainline earnings between 2012 and 2011 is affected by the change in tolling methodology. As noted previously, from July 1, 2011 onward, Canadian Mainline earnings (excluding Lines 8 and 9) were governed by the CTS, whereas operations for the first six months of 2011 were governed by a series of agreements, the most significant being the ITS applicable to the mainline system and the Terrace and Alberta Clipper agreements.

Canadian Mainline revenues for the year ended December 31, 2012 reflected increased volumes and a higher Canadian Mainline IJT Residual Benchmark Toll. Volume throughput in 2012 was impacted by market conditions as incremental oil sands crude production in Alberta and strong production growth out of the Bakken in North Dakota bolstered supply to midwest markets and placed increased downward pressure on crude oil prices in that market. This discounted crude oil, coupled with strong refining margins, increased demand in the midwest for Canadian and Bakken crude oil supply and drove increased long haul barrels on Canadian Mainline and EEP’s Lakehead System. However, during the fourth quarter of 2012, Canadian Mainline was not able to capture the full throughput benefit of the increased supply available to it due to capacity limitations which arose from pressure restrictions being applied to certain lines pending completion of inspection and repair programs. An increase in operating and administrative costs, primarily due to higher employee related costs and higher leak remediation costs, also impacted 2012 adjusted earnings.

Supplemental information on Canadian Mainline adjusted earnings for the years ended December 31, 2013 and 2012 and for the six month period from July 1, 2011, the effective date of the CTS, to December 31, 2011 are as follows:

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	Year ended				Six months ended
	December 31,				December 31,
	2013		2012		2011
(millions of Canadian dollars)
Revenues	1,434		1,367		618
Expenses
Operating and administrative	407		382		194
Power	122		112		54
Depreciation and amortization	244		219		104
	773		713		352
	661		654		266
Other income/(expense)	3		(4	)	5
Interest expense	(162	)	(131	)	(66	)
	502		519		205
Income taxes	(42	)	(87	)	(31	)
Adjusted earnings	460		432		174
Effective United States to Canadian dollar exchange rate1	0.999		0.971		0.972

December 31,	2013	2012	2011
(United States dollars per barrel)
IJT Benchmark Toll2	$3.98	$3.94	$3.85
Lakehead System Local Toll3	$2.18	$1.85	$2.01
Canadian Mainline IJT Residual Benchmark Toll4	$1.80	$2.09	$1.84

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

2The 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, 2013, the IJT Benchmark Toll increased from US$3.94 to US$3.98.

3The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective July 1, 2012, this toll increased from US$1.76 to US$1.85 and effective April 1, 2013, it subsequently increased to US$2.13. Effective July 1, 2013, this toll increased from US$2.13 to US$2.18.

4The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. Effective April 1, 2013, this toll decreased from US$2.09 to US$1.81 and, effective July 1, 2013, this toll decreased from US$1.81 to US$1.80. For any shipment, this toll is the difference between the IJT Benchmark Toll for that shipment and the Lakehead System Local Toll for that shipment.

Throughput Volume1

	Q1	Q2	Q3	Q4	Total
2013	1,783	1,604	1,736	1,827	1,737
2012	1,687	1,659	1,617	1,622	1,646
2011	1,602	1,457	1,565	1,594	1,554

1Throughput, presented in thousand 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. 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 which 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.

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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.

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.

Prior to the implementation of the CTS, revenues on the Canadian Mainline were recognized in a manner consistent with the underlying agreements as approved by the regulator, in accordance with rate-regulated accounting. The Company discontinued the application of rate-regulated accounting to its Canadian Mainline (excluding Lines 8 and 9) on a prospective basis commencing July 1, 2011. A regulatory asset of approximately $470 million related to deferred income taxes recorded at the date of discontinuance continued to be recognized as the Company retains the ability to recover deferred income taxes under an NEB order governing flow-through income tax treatment. The regulatory asset balance at the date of discontinuance related to tolling deferrals recognized in prior periods was being recovered through a surcharge to the CLT and IJT.

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 and Woodland 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, which links the Athabasca oil sands in the Fort McMurray region to a pipeline hub at Hardisty, Alberta. In March 2013, the Athabasca Pipeline’s capacity was increased to 430,000 bpd and in December 2013 was further expanded to 570,000 bpd, depending on the viscosity of crude being shipped. The Company has a long-term (30-year) take-or-pay contract with the major shipper on the Athabasca Pipeline which commenced in 1999. Revenues are recorded based on the contract terms negotiated with the major shipper, rather than the cash tolls collected.

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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 had an initial design capacity, dependent on crude slate, of up to 350,000 bpd. The pipeline was further expanded to 415,000 bpd in the fourth quarter of 2012 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. See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers for details of the transfer.

Results of Operations

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.

Adjusted earnings for the year ended December 31, 2012 were $110 million compared with $111 million for the year ended December 31, 2011. Higher shipped volumes and increased tolls on certain laterals, and higher earnings from an annual escalation in storage and terminalling fees were more than offset by higher operating and administrative expense, and higher depreciation expense. Adjusted earnings for 2012 also included contributions from new regional infrastructure, the Woodland and Wood Buffalo pipelines, placed into service in the fourth quarter of 2012, although offset by a lack of earnings from assets sold to the Fund in December 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, which is located approximately 70 kilometres (45 miles) southeast of Fort McMurray, Alberta. Line 37 is part of Regional Oil Sands System and 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 which 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. The southern segment of the Athabasca pipeline was returned to service at normal pressure on June 23, 2013, with the northern segment resuming service on June 30, 2013 at reduced operating pressure following completion of extensive engineering and geotechnical analysis. Full service on the northern segment of the Athabasca pipeline was restored on July 11, 2013. The Waupisoo pipeline between Cheecham and Edmonton restarted on June 25, 2013 at normal operating pressure. The Wood Buffalo pipeline was restarted on July 2, 2013 at reduced pressure pending completion of further geotechnical analysis in the incident area and, on July 19, 2013, the Wood Buffalo pipeline was returned to normal operating pressure. The Woodland pipeline had been in the process of linefill at the time of the shutdown; linefill activities were completed in the third quarter of 2013.

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The costs expected to be incurred in connection with this incident are approximately $56 million after-tax and before insurance recoveries. Lost revenue associated with the shutdown of Line 37 and the pipelines sharing a corridor with Line 37 was minimal. Enbridge carries liability insurance for sudden and accidental pollution events and expects to be reimbursed for its covered costs, subject to a $10 million deductible. The integrity and stability costs associated with remediating the impact of the high water levels are 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. Federal and provincial governmental agencies have initiated investigations into the Line 37 crude oil release and costs estimates exclude any potential fines or penalties.

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 return on equity (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.

Results of Operations

Southern Lights earnings increased to $49 million for the year ended December 31, 2013 compared with $42 million for the year ended December 31, 2012 and $41 million for the year ended December 31, 2011 primarily due to higher recovery of negotiated depreciation rates in 2013 transportation tolls.

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 from Cushing, Oklahoma to Freeport, Texas, as well as the Texas City Terminal and Distribution System which serves refineries in the Houston and Texas City areas. The Seaway Pipeline also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast.

The reversal of the Seaway Pipeline, enabling it to transport crude oil from the oversupplied hub in Cushing, Oklahoma to the Gulf Coast, was completed in May 2012, providing initial capacity of 150,000 bpd. In January 2013, the completion of further pump station additions and modifications increased the capacity available to shippers to up to 400,000 bpd, depending on crude slate. Actual throughput experienced in 2013 was curtailed due to constraints on third party takeaway facilities. A lateral from the Seaway Jones Creek facility to the ECHO Terminal in Houston, Texas, completed in January 2014, is expected to eliminate these constraints. Spot volumes on Seaway Pipeline can also be impacted by the spread between WTI and Louisiana Light Sweet crude oil prices.

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 contracts. The FERC issued a decision denying the PDO on procedural grounds but stated that it will uphold its longstanding policy of honouring contracts.

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 uncommitted and committed 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. There is no prescribed time line for a ruling from the FERC.

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Results of Operations

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. The Seaway Pipeline reversal was completed in May 2012 providing initial capacity of 150,000 bpd. In January 2013, the completion of further pump station additions and modifications increased the capacity available to shippers to up to 400,000 bpd, depending on crude slate. As noted above, 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. These takeaway constraints are anticipated to be relieved in the first quarter of 2014. Partially offsetting the earnings increase was higher financing costs and higher depreciation expense from an increased asset base.

Seaway Pipeline earnings for the year ended December 31, 2012 were $24 million and reflected preliminary service at an approximate capacity of 150,000 bpd which commenced in May 2012. The $3 million loss recognized for the year ended December 31, 2011 was related to early stage business development costs that were not eligible for capitalization.

SPEARHEAD PIPELINE

Spearhead Pipeline delivers crude oil from the Flanagan, Illinois delivery point of 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. 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 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 expenses, 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.

Spearhead Pipeline adjusted earnings were $37 million for the year ended December 31, 2012 compared with $17 million for the year ended December 31, 2011. Spearhead Pipeline adjusted earnings increased as a result of higher volumes and tolls, partially offset by higher operating and administrative costs, including power and repairs and maintenance. Volumes significantly increased over 2011 due to higher commodity price differentials which increased demand at Cushing, Oklahoma in anticipation of additional capacity on the Seaway Pipeline for further transportation to the Gulf Coast.

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 recently expanded 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. See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers for details of the transfer.

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Results of Operations

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.

In 2012, Feeder Pipelines and Other earnings were $10 million compared with a loss of $1 million for the year ended December 31, 2011. The increase in earnings was primarily a result of a higher contribution from Olympic due to a tariff increase, higher volumes on Toledo Pipeline and increased terminalling fees. In 2011, earnings from Toledo Pipeline were negatively impacted by integrity work on Lines 6A and 6B of EEP’s Lakehead System.

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.

Enbridge seeks to mitigate utilization risks within its control. The market access and expansion projects under development are expected to reduce capacity bottlenecks and introduce new markets for customers. Liquids Pipelines also works with the shipper community to enhance scheduling efficiency and communications as well as makes continuous improvements to scheduling models and timelines to alleviate pipeline restrictions. Throughput risk is also partially mitigated by provisions in the CTS agreement, which allows Enbridge to negotiate an amendment to the agreement in the event certain minimum threshold volumes are not met.

Operational and Economic Regulation

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

Regulatory scrutiny over the integrity of Liquids Pipelines assets has the potential to increase operating costs or limit future projects. Potential regulation upgrades and 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.

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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. 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 could have an adverse effect on the Company’s revenues and earnings. The Company believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers which govern the majority of the segment’s assets and the involvement of its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations; however, the risk that a regulator could overturn long-term agreements between the Company and shippers continues to exist.

Competition

Competition may result in a reduction in demand for the Company’s services, fewer new 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 are available to ship western Canadian liquids hydrocarbons to markets in either Canada or the United States. Competition also arises from existing and proposed pipelines that provide, or are proposed to provide, access to market areas currently served by the Company’s liquids pipelines, such as proposed projects expected to serve the Gulf Coast or eastern markets, as well as from proposed projects in the Alberta regional oil sands market. Additionally, crude oil price differentials and the long lead-times required to build new pipeline capacity continues to make transportation of crude oil by rail competitive where railways are able to access 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 its 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.

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.

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GAS DISTRIBUTION

EARNINGS

	2013		2012		2011
(millions of Canadian dollars)
Enbridge Gas Distribution Inc. (EGD)	156		149		135
Other Gas Distribution and Storage	20		27		38
Adjusted earnings	176		176		173
EGD - gas transportation costs out-of-period adjustment	(56	)	-		-
EGD - (warmer)/colder than normal weather	9		(23	)	1
EGD - tax rate changes	-		(9	)	-
EGD - recognition of regulatory asset	-		63		-
Other Gas Distribution and Storage - regulatory deferral write-off	-		-		(262	)
Earnings/(loss) attributable to common shareholders	129		207		(88	)

Adjusted earnings from Gas Distribution were $176 million for the year ended December 31, 2013 compared with $176 million for 2012 and $173 million for the year ended December 31, 2011. EGD’s operating results for 2013 are pursuant to a one year cost of service settlement, following completion of a five year Incentive Regulation (IR) term at the end of 2012. EGD adjusted earnings growth reflected the positive impacts of a larger customer base and the absence of earnings sharing with natural gas customers under the one year cost of service settlement. In 2012, adjusted earnings from Other Gas Distribution and Storage were negatively impacted compared with the prior year due to changes in rate setting methodology applicable to gas distribution operations in New Brunswick.

Gas Distribution earnings were impacted by the following adjusting items:

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

·EGD earnings for all periods were adjusted to reflect the impact of weather.

·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. See Gas Distribution – Enbridge Gas Distribution Inc. – Rate Application.

·Other Gas Distribution and Storage earnings for 2011 reflected the discontinuation of rate-regulated accounting for Enbridge Gas New Brunswick Inc. (EGNB) and the related write-off of a deferred regulatory asset and certain capitalized operating costs, net of tax. See Gas Distribution – Other Gas Distribution and Storage – Enbridge Gas New Brunswick Inc. – Regulatory Matters.

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 by the New York State Public Service Commission.

Rate Application

EGD’s rates for 2013 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.

Prior to 2013, EGD operated under a revenue cap IR mechanism, calculated on a revenue per customer basis, with the OEB for a five-year period between 2008 and 2012. Under the IR 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. The earnings sharing mechanism resulted in the return of revenue to customers of $10 million for the year ended December 31, 2012 and $13 million for the year ended December 31, 2011. The earnings sharing mechanism, which was previously in effect under IR, did not apply to the 2013 Settlement.

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The 2013 Settlement established the right to recover an existing OPEB liability 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.

In July 2013, EGD filed an application with the OEB for the setting of rates through a customized IR mechanism for the period of 2014 through 2018. A decision is anticipated in the second quarter of 2014.  The objectives of the IR plan are as follows:

·reduce regulatory costs with less frequent hearings;

·provide incentives for improved efficiency;

·provide more flexibility for utility management; and

·provide for necessary infrastructure upgrades and safety and reliability projects.

Results of Operations

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 revenue, which results 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.

Adjusted earnings for the year ended December 31, 2012 were $149 million compared with $135 million for the year ended December 31, 2011. The increase in EGD’s adjusted earnings was primarily due to customer growth, favourable rate variances and higher pipeline capacity optimization. This growth was partially offset by an increase in system integrity and safety-related costs and higher employee costs, as well as higher depreciation due to a higher in-service asset base.

OTHER GAS DISTRIBUTION AND STORAGE

Other Gas Distribution includes natural gas distribution utility operations in Quebec and New Brunswick, the most significant being EGNB (100% owned and operated by the Company), which owns the natural gas distribution franchise in the province of New Brunswick. EGNB has approximately 11,000 customers and is regulated by the New Brunswick Energy and Utilities Board (EUB).

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 which 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.

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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. Accordingly, EGNB has also indefinitely adjourned its application for judicial review of the EUB’s original decision regarding rates to take effect as of October 1, 2012. EGNB filed its 2014 rate application on October 1, 2013, the outcome of which will determine rates during the next rate period, and a decision is expected in the first quarter of 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.

Results of Operations

Other Gas Distribution and Storage adjusted earnings were $20 million for the year ended December 31, 2013 compared with $27 million for the year ended December 31, 2012 and 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.

Other Gas Distribution and Storage adjusted earnings were $27 million for the year ended December 31, 2012 compared with $38 million for the year ended December 31, 2011. This adjusted earnings decrease was primarily due to the change in rate setting methodology applicable to EGNB enacted in 2012. Effective January 1, 2012, the discontinuance of rate-regulated accounting at EGNB resulted in earnings subject to increased variability, including quarterly seasonality, as there was no further accumulation of the regulatory deferral account. Earnings for 2012 were impacted by lower volume due to a decrease in demand for natural gas, which was the result of a warmer than normal winter.

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 interveners on rate negotiations. The terms of rate negotiations are also reviewed by the Company’s legal, regulatory and finance teams. Specific to the 2014 IR plan negotiations, the Company has used Alternate Dispute Resolution process when negotiating with the regulators and interveners in order to minimize more costly and time consuming formal hearings.

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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. 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 continues 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

	2013		2012		2011
(millions of Canadian dollars)
Aux Sable	49		68		55
Energy Services	75		40		56
Alliance Pipeline US	43		39		39
Vector Pipeline	22		22		23
Enbridge Offshore Pipelines (Offshore)	(2	)	(3	)	(7	)
Other	16		10		14
Adjusted earnings	203		176		180
Aux Sable - changes in unrealized derivative fair value gains/(loss)	-		10		(7	)
Energy Services - changes in unrealized derivative fair value gains/(loss)	(206	)	(537	)	125
Offshore - asset impairment loss	-		(105	)	-
Other - changes in unrealized derivative fair value gains/(loss)	(61	)	-		24
Earnings/(loss) attributable to common shareholders	(64	)	(456	)	322

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Adjusted earnings from Gas Pipelines, Processing and Energy Services were $203 million for the year ended December 31, 2013 compared with $176 million for the year ended December 31, 2012 and $180 million for the year ended December 31, 2011. Changing market conditions has resulted in variability in earnings for this segment as lower fractionation margins in 2013 resulted in lower contributions from Aux Sable, while favourable market conditions gave rise to greater margin opportunities in Energy Services in 2013. The increase in earnings in 2013 compared with 2012 also reflected contributions from additional natural gas midstream and renewable energy investments.

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

·Aux Sable earnings for 2012 and 2011 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. A gain or loss on such a financial derivative corresponds to a similar but opposite loss or gain on the value of the underlying physical transaction which is expected to be realized in the future when the physical transaction settles. Unlike the change in the value of the financial derivative, the gain or loss on the value of the underlying physical transaction is not recorded for financial statement purposes until the periods in which it is realized.

·Adjusted earnings for 2013 excluded a one-time realized loss of $58 million incurred to close out derivative contracts used to hedge forecasted Energy Services transactions which are no longer probable to occur.

·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. See Gas Pipelines, Processing and Energy Services – Enbridge Offshore Pipelines – Asset Impairment for further details.

·Other earnings/(loss) for 2013 and 2011 reflected changes in unrealized fair value gains or losses on derivative financial instruments. In 2013, the unrealized loss reflected the change in the value of 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 (collectively Aux Sable). Aux Sable US owns and operates a NGL extraction and fractionation plant outside Chicago, Illinois near the terminus of Alliance. The plant extracts NGL from the liquids-rich natural gas transported on Alliance, as necessary for Alliance 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 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 2013, 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 decline over the next few years while certain producer contract commitments 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.

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Results of Operations

Aux Sable adjusted earnings for the year ended December 31, 2013 were $49 million, a decrease from earnings of $68 million for the year ended December 31, 2012. The decrease was mainly due 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 adjusted earnings were $68 million for the year ended December 31, 2012 compared with $55 million for the year ended December 31, 2011. Adjusted earnings increased primarily due to higher realized fractionation margins and earnings contributions from the Prairie Rose Pipeline and the Palermo Conditioning Plant acquired in July 2011.

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 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 to the Aux Sable plant can directly and adversely affect the margin earned through the upside sharing mechanism. Alliance is well positioned to deliver incremental liquids-rich gas production from new developments in the Montney and Bakken regions, thereby mitigating volume risk. In addition, Aux Sable attracts liquids-rich gas to Alliance 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. Any commodity price exposure created from this physical business is closely monitored and must comply with the Company’s formal risk management policies.

Tidal Energy also provides natural gas marketing services, including marketing natural gas to optimize commitments on certain natural gas pipelines. To the extent transportation costs exceed the basis (location) differential, earnings will be negatively affected. Tidal Energy also provides natural gas supply, transportation, balancing and storage for third parties, leveraging its natural gas marketing expertise and access to transportation capacity.

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Results of Operations

Energy Services adjusted earnings were $75 million for the year ended December 31, 2013, an increase over adjusted earnings of $40 million for the year ended December 31, 2012. Adjusted earnings from Energy Services are dependent on market conditions, including but not limited to, quality, time and location differentials, and results achieved in one period may not be indicative of results to be achieved in future periods. Dependency on market conditions was evident in the trend in quarterly earnings compared with the prior year whereby wide location and crude grade differentials 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 limit tank management opportunities. Although profitability declined in most lines of business, the fourth quarter loss 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.

Energy Services adjusted earnings decreased from $56 million for the year ended December 31, 2011 to $40 million for the year ended December 31, 2012. The decline was primarily due to changing market conditions which gave rise to fewer margin opportunities in crude oil and NGL marketing.

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, including 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, optimizing relationships with affiliated entities and establishing long-term relationships with clients.

ALLIANCE PIPELINE US

The Alliance System, which includes both the Canadian and United States 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 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 bcf/d and 1.325 bcf/d, respectively. Enbridge owns 50% of Alliance Pipeline US, while the Fund, described under Sponsored Investments, owns 50% of Alliance Pipeline Canada.

Alliance connects with the Aux Sable NGL extraction and fractionation plant. Natural gas transported on Alliance 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.

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Alliance Pipeline US runs adjacent to the Bakken oil formation in North Dakota which offers new incremental sources of liquids-rich natural gas for delivery to downstream markets. In February 2010, a new receipt point on the pipeline near Towner, North Dakota was placed into service. The receipt point connects to the Prairie Rose Pipeline and provides shippers operating out of the Bakken access to Alliance. In September 2013, Alliance Pipeline US completed construction of the Tioga Lateral which will facilitate delivery of natural gas from Hess’ Tioga field processing plant in the Bakken to downstream markets.

Transportation Contracts

Alliance Pipeline US has long-term, take-or-pay contracts to transport substantially all its 1.466 bcf/d of natural gas capacity. These contracts permit Alliance Pipeline US, whose operations are regulated by the FERC, to recover the cost of service, which includes operating and maintenance costs, the cost of financing, an allowance for income tax, an annual allowance for depreciation and an allowed ROE of 10.9%.

Alliance Pipeline US is in discussions with the shipper community regarding its service offerings post the December 2015 expiry of the majority of existing contracts.

Results of Operations

Alliance Pipeline US earnings were $43 million for the year ended December 31, 2013 compared with earnings of $39 million for each of the years ended December 31, 2012 and 2011. 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 Pipeline which was placed into service in 2013.

VECTOR PIPELINE

Vector, which includes both the Canadian and United States portions of the pipeline system, consists of 560 kilometres (348 miles) of mainline natural gas transmission pipeline between the Chicago, Illinois hub and a storage complex at Dawn, Ontario. Vector’s primary sources of supply are through interconnections with Alliance 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.

Transportation Contracts

The total long haul capacity of Vector is approximately 87% 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 2013, shippers under negotiated rate transportation contracts which represent 20% of the system’s long haul capacity elected to extend their commitments beyond December 1, 2016 and preserve the option to extend their contracts on an annual basis. Vector is entitled to additional compensation from shippers that terminate their contracts prior to the November 30, 2020 expiry date.

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 2013, 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 2013, maximum tolls include an ROE component of 10.5% after-tax.

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Results of Operations

Vector earnings were $22 million for the year ended December 31, 2013, comparable with $22 million for the year ended December 31, 2012 and $23 million for the year ended December 31, 2011, respectively, and reflected the stable, cost of service commercial arrangement in place for these years.

BUSINESS RISKS

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

Asset Utilization

Currently, natural gas pipeline capacity out of the WCSB exceeds supply, due to the low price of natural gas and increased production from new shale gas developments. Alliance Pipeline US and Vector have been unaffected by this excess supply environment to date mainly because of long-term capacity contracts extending primarily to 2015. However, excess supply and depressed natural gas prices have led to a reduction or deferral of investment in upstream gas development, and could negatively impact re-contracting beyond this term. Additionally, increased supply from new shale developments including the Marcellus shale formation, which is among the largest gas plays in North America, could displace gas from the WCSB to the United States midwest further increasing re-contracting risk.

The re-contracting risk is somewhat mitigated as the Alliance System is well positioned to deliver incremental liquids-rich gas production from developments in the Montney and Bakken regions to the Aux Sable NGL extraction and fractionation plant. The Alliance System 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.

Competition

Alliance Pipeline US 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. 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 US because of location, facilities or other factors. In addition, these pipelines could charge rates or provide transportation services to locations that result in greater net profit for shippers, with the effect of forcing Alliance Pipeline US to realize lower revenues and cash flows. The ability of Alliance Pipeline US to cost-effectively transport liquids-rich gas serves to enhance its competitive position.

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 and Alliance pipelines also face 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.

Economic Regulation

Both the United States portion of Vector and Alliance Pipeline US operations are subject to regulation by the FERC. If tariff rates 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 US files its annual rates with the FERC for approval.

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The FERC has intensified its oversight of financial reporting, risk standards and affiliate rules and has issued new standards 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.

ENBRIDGE OFFSHORE PIPELINES

Offshore is comprised of 13 active natural gas gathering and FERC-regulated transmission pipelines and one active oil pipeline with a capacity of 60,000 bpd, in five major corridors in the Gulf of Mexico, extending to deepwater developments. These pipelines include almost 2,600 kilometres (1,600 miles) of underwater pipe and onshore facilities with total capacity of approximately 7.3 bcf/d. Offshore currently moves approximately 45% of offshore deepwater gas production through its systems 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 which 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 utilized on a go forward basis and included in the WRGGS, Big Foot Pipeline, Venice and Heidelberg commercially secured projects differs from the historic model. These new projects have a base level return which is locked in through either ship-or-pay commitments or fixed demand charge payments. If volumes reach producer 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 Venice 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. Adjustment is allowed for many of the Heidelberg project variables affecting 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 which 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.

Results of Operations

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 earnings included the Venice expansion 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 volumes on the majority of Offshore’s pipelines due to decreased production in the Gulf of Mexico. The challenging market conditions which impacted Offshore in 2013 is expected to persist and be a drag on Offshore earnings until such time as the WRGGS and Big Foot Pipeline are placed into service, which are expected to occur in the third quarter of 2014 and the second quarter of 2015, respectively.

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For the year ended December 31, 2012, Offshore incurred an adjusted loss of $3 million compared with a loss of $7 million for the year ended December 31, 2011. Offshore realized losses due to weak volumes from delayed drilling programs and scheduled production outages by producers in the Gulf of Mexico. The decrease in loss year-over-year resulted from a higher transportation rate for volumes shipped on the Stingray Pipeline System, a reduction in interest expense and a $2 million favourable impact related to the reversal of a shipper reserve pertaining to a rate case from 2011.

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 future decline in crude oil prices could change the potential for future investment opportunities. Further, a sustained decline in either natural gas or crude oil commodity prices could 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 an increasing number of competitors willing to construct and operate production host platforms for future deepwater prospects. Offshore has been able to capture key opportunities, 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 sub-sea development of smaller fields 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 planned Big Foot and Heidelberg pipelines. Given rates of decline, offshore pipelines typically have available capacity, resulting in significant competition for new developments in the Gulf of Mexico. Competing developments 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. In 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 may still occur.

OTHER

Other includes interests in approximately 1,250 MW of the enterprise-wide portfolio of 1,800 MW of renewable power generating assets. The balance of the portfolio is held by the Fund. Of the interests presented within Other, 830 MW represents active production from four wind farms and one solar asset while the remainder represents interests in growth projects under construction. Also included in Other is MATL, the Company’s first power transmission asset, and its natural gas midstream business, including Cabin located in northeastern British Columbia.

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To optimize funding of its enterprise-wide slate of growth projects, Enbridge may drop down assets to its Sponsored Investments. In 2012, Greenwich Wind Energy Project (Greenwich), Amherstburg Solar Project (Amherstburg) and Tilbury Solar Project (Tilbury) were transferred to the Fund, following the 2011 transfer of the Ontario Wind, Sarnia Solar and Talbot Wind energy projects. Earnings contributions from these assets, net of noncontrolling interests, are reflected within Sponsored Investments from the date the assets were transferred to the Fund. See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers.

Results of Operations

Adjusted earnings from Other for the year ended December 31, 2013 were $16 million compared with $10 million for the year ended December 31, 2012. Higher earnings were mainly attributable to the commissioning of Lac Alfred and contributions from fees earned on the Company’s investment in Cabin, for which earnings recognition commenced in December 2012. Partially offsetting the increase in adjusted earnings was 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 (Cedar Point) due to lower wind resources.

Other adjusted earnings for the year ended December 31, 2012 were $10 million compared with $14 million for the year ended December 31, 2011. The decrease in adjusted earnings was primarily due to the sale of Ontario Wind, Sarnia Solar and Talbot Wind energy projects to the Fund in October 2011, followed by the sale of Greenwich, Amherstburg and Tilbury to the Fund in December 2012. Higher business development costs also contributed to the decrease in adjusted earnings. Partially offsetting this increase were the contributions from Cedar Point and Greenwich, which were commissioned in late 2011, and Silver State North Solar Project (Silver State) which was commissioned in early 2012.

SPONSORED INVESTMENTS

EARNINGS

	2013		2012		2011
(millions of Canadian dollars)
Enbridge Energy Partners, L.P. (EEP)	165		141		151
Enbridge Energy, Limited Partnership (EELP)	38		38		42
Enbridge Income Fund (the Fund)	110		85		50
Adjusted earnings	313		264		243
EEP - leak insurance recoveries	6		24		50
EEP - leak remediation costs	(44	)	(9	)	(33	)
EEP - changes in unrealized derivative fair value gains/(loss)	(6	)	(2	)	3
EEP - tax rate differences/changes	(3	)	-		-
EEP - gain on sale of non-core assets	2		-		-
EEP - NGL trucking and marketing investigation costs	-		(1	)	(3	)
EEP - prior period adjustment	-		7		-
EEP - shipper dispute settlement	-		-		8
EEP - lawsuit settlement	-		-		1
EEP - impact of unusual weather conditions	-		-		(1	)
Earnings attributable to common shareholders	268		283		268

Adjusted earnings from Sponsored Investments were $313 million for the year ended December 31, 2013 compared with $264 million for the year ended December 31, 2012 and $243 million for the year ended December 31, 2011. The increase in adjusted earnings resulted from increased contributions from the Fund following the transfer of certain renewable energy and crude oil storage assets from Enbridge and its wholly-owned subsidiaries in late 2012 and late 2011. EEP also contributed to the 2013 increase in year-over-year adjusted earnings primarily due to Enbridge’s investment in preferred units of EEP issued in 2013, as well as higher incentive distributions.

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Sponsored Investment earnings were impacted by the following adjusting items:

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

·EEP earnings for each period included charges related to estimated costs, before insurance recoveries, associated with the Line 6B crude oil release. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Line 14 Crude Oil Release and Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases.

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

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

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

·EEP earnings for 2012 and 2011 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.

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

·EEP earnings for 2011 included proceeds from the settlement of a shipper dispute related to oil measurement adjustments in prior years.

·EEP earnings for 2011 included proceeds related to the settlement of a lawsuit during the first quarter of 2011.

·EEP earnings for 2011 included an unfavourable effect related to decreased volumes due to uncharacteristically cold weather in February 2011 that disrupted normal operations of its natural gas systems.

ENBRIDGE ENERGY PARTNERS, L.P.

EEP owns and operates crude oil and liquid petroleum transportation and storage assets and natural gas and NGL gathering, treating, processing, transportation 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. In 2013, EEP placed into service several assets including the Texas Express NGL System, Ajax Plant and the Bakken Expansion Program. Subsidiaries of Enbridge provide services to EEP in connection with the operation of its liquids assets, including the Lakehead System.

EEP holds its natural gas and NGL midstream assets through a combination of direct and indirect holdings. As at December 31, 2013, EEP’s direct interest in entities or partnerships holding the natural gas and NGL operations was approximately 61%, with the remaining ownership held by Midcoast Energy Partners, L.P. (MEP), a publicly listed partnership trading on the New York Stock Exchange. The balance of EEP’s interest in the natural gas and NGL operations is held indirectly through ownership of the general partner (GP) interest, an approximate 52% limited partner interest and all incentive distribution rights of MEP. For further discussion refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Midcoast Energy Partners, L.P. Initial Public Offering.

Ownership 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 ownership interest in EEP is reduced. At December 31, 2013, Enbridge’s ownership interest in EEP was 20.6% (2012 - 21.8%; 2011 - 23.0%). The Company’s average ownership interest in EEP during 2013 was 21.1% (2012 - 23.0%; 2011 - 24.4%). 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.

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Distributions

EEP makes quarterly distributions of its available cash to its common unitholders. Under the Partnership Agreement, Enbridge Energy Company, Inc. (EECI), a wholly owned subsidiary of Enbridge, 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 as follows:

	Unitholders including Enbridge	GP Interest
Quarterly cash distributions per unit1:
Up to $0.295 per unit	98%	2%
First target - $0.295 per unit up to $0.350 per unit	85%	15%
Second target - $0.350 per unit up to $0.495 per unit	75%	25%
Over second target - cash distributions greater than $0.495 per unit	50%	50%

1Distributions restated to reflect EEP’s two-for-one stock split which was effective April 2011.

In 2013, EEP paid a quarterly distribution of $0.5435 per unit to common unitholders. In 2013, Enbridge received from EEP intercompany GP incentive distributions of US$130 million (2012 - US$116 million; 2011 - US$93 million).

Results of Operations

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. Rail competition is expected to persist as rail provides transportation service to certain markets not currently accessible by pipelines. 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.

Adjusted earnings from EEP were $141 million for the year ended December 31, 2012 compared with $151 million for the year ended December 31, 2011. Adjusted earnings from EEP for 2012 included higher GP incentive income and strong results from the liquids business primarily due to higher average delivery volumes and increased tolls on all major liquids systems, as well as contributions from storage terminal and other facilities that were placed into service during 2012. Earnings from the natural gas business decreased as a result of lower natural gas and NGL prices. Earnings were also negatively impacted by an increase in operating and administrative costs, specifically pipeline integrity costs, personnel costs and higher property taxes.

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 Pipeline and Hazardous Materials Safety Administration (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 will again consider the status of the pipeline in light of information they acquire throughout 2014.

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The total estimated cost for 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 revenue 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.

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 Environmental Protection Agency (EPA), the Michigan Department of Natural Resources and Environment and other federal, state and local agencies.

As at December 31, 2013, EEP’s total cost estimate for the Line 6B crude oil release was US$1,122 million ($181 million after-tax attributable to Enbridge) which is an increase of US$302 million ($44 million after-tax attributable to Enbridge) compared to the December 31, 2012 estimate. This total estimate is before insurance recoveries and excludes additional fines and penalties other than those discussed in Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – Legal and Regulatory Proceedings, below. On March 14, 2013, EEP received an order from the EPA (the Order) 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. 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. The Order states the work must be completed by December 31, 2013. EEP has currently completed substantially all of the SORA, with the exception of required dredging in and around Morrow Lake and its delta. EEP is in the process of working with the EPA to ensure this work is completed as soon as reasonably possible, inclusive of obtaining the necessary state and local permitting that is required and considering weather conditions.

Of the US$302 million increase compared with December 31, 2012 related to the Line 6B crude oil release, US$280 million is primarily related to additional work required by the Order including further refinement and definition of the additional dredging scope per the Order and all associated environmental, permitting, waste removal and other related costs, as well as increased dredge activity in and around Morrow Lake and the delta area. The actual costs incurred may differ from the foregoing estimate as EEP completes the work plan with the EPA related to the Order and works with other regulatory agencies to assure its work plan complies with their requirements. Any such incremental costs will not be recovered under EEP’s insurance policies as the costs for the incident at December 31, 2013 exceeded the limits of the Company’s insurance coverage. The remaining increase of US$22 million reflected an estimate of the minimum amount of civil penalties EEP may be assessed under the Clean Water Act of the United States (Clean Water Act) in respect of the Line 6B crude oil release. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – 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, 2013. 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.

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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.

The total estimated cost for the Line 6A crude oil release remains at approximately US$48 million ($7 million after-tax attributable to Enbridge), before insurance recoveries and excluding fines and penalties. These costs included emergency response, environmental remediation and cleanup activities with the crude oil release. 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, EEP’s 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 such as those incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties.

The claims for 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. Based on EEP’s remediation spending through December 31, 2013, Enbridge and its affiliates have exceeded the limits of their coverage under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy. For the years ended December 31, 2013 and 2012, EEP recognized US$42 million ($6 million after-tax attributable to Enbridge) and US$170 million ($24 million after-tax attributable to Enbridge), respectively, of insurance recoveries as reductions to Environmental costs in the Consolidated Statements of Earnings. As at December 31, 2013, 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. While EEP believes the claims for the remaining US$103 million are covered under the policy, there can be no assurance that EEP will prevail in this lawsuit.

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Effective May 1, 2013, Enbridge renewed its comprehensive property and liability insurance programs, under which EEP is insured through April 30, 2014, with a current liability aggregate limit of US$685 million, including sudden and accidental pollution liability. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement EEP has entered into with Enbridge and another Enbridge subsidiary.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Lines 6A and 6B crude oil releases. Approximately 30 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.

As at December 31, 2013, included in EEP’s estimated costs related to the Line 6B crude oil release is US$30 million in fines and penalties. Of this amount, US$3.7 million related to civil penalties assessed by PHMSA that EEP paid during the third quarter of 2012. The total also included an amount of US$22 million related to civil penalties EEP expects to be required to pay 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$22 million represents an estimate of the minimum amount which may be assessed, excluding costs of injunctive relief, if any, 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. Discussions with governmental agencies regarding fines and penalties 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.

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.

Midcoast Energy Partners, L.P. Initial Public Offering

In May 2013, EEP formed MEP as its wholly owned subsidiary. Subsequently, on November 13, 2013, MEP completed its initial public offering (IPO) 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.

EEP, through certain of its subsidiaries, holds a 2% GP interest and the remaining limited partner interest in MEP. 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 ownership of the GP and all the incentive distribution rights in MEP. The finalization of the transaction resulted in a partial monetization of EEP’s natural gas and NGL midstream assets through sale to noncontrolling interests (being MEP’s public unitholders).

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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.

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 will now be 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. For further discussion refer to Liquidity and Capital Resources.

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, which is a 1,670-kilometre (1,000 mile) crude oil pipeline that provides service between Hardisty, Alberta and Superior, Wisconsin with capacity of 450,000 bpd. Enbridge funded 66.7% of the project’s equity requirements through EELP, while 66.7% of the debt funding was made through EEP.

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 see 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 $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 revenue from several small components of the Eastern Access project which were placed into service in 2013, including the Line 5 expansion.

Earnings from EELP were $38 million for the year ended December 31, 2012 compared with $42 million for the year ended December 31, 2011 due to a reduction in rates on Alberta Clipper which took effect April 1, 2012.

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.

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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 works with the shipper community to enhance scheduling efficiency and communications as well as makes continuous improvements to models and timelines to alleviate pipeline restrictions.

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

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

Regulatory scrutiny over the integrity of EEP’s assets, in particular its liquids assets, has the potential to increase operating costs or limit future projects. Potential regulation upgrades and 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, directly or through industry associations. The Company also develops robust response plans to regulatory changes or enforcement actions.

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 by the regulators could have an adverse effect on the Company’s revenues and earnings. 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 regulatory risk is reduced through the negotiation of long-term agreements with shippers which govern the majority of the segment’s assets and the involvement of its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations; however, the risk that a regulator could overturn long-term agreements between the Company and shippers continues to exist.

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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 Canada. Within Green Power, the Fund has interests in over 500 MW of 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 as well as the Hardisty Contract Terminals and Hardisty Storage Caverns located near Hardisty, Alberta.

Crude Oil Storage and Renewable Energy Transfers

In December 2012, ENF and the Fund finalized the acquisition of 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 additional Enbridge Commercial Trust (ECT) preferred units to Enbridge. ENF in turn issued additional common shares to the public and to Enbridge. Enbridge also provided bridge debt financing (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.

In October 2011, the Fund also acquired the Ontario Wind, Sarnia Solar and Talbot Wind energy projects from a wholly-owned subsidiary of Enbridge for an aggregate price of approximately $1.2 billion. The transaction was financed by the Fund through a combination of debt and equity, including 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 provided Bridge Financing for the balance of the purchase price. Enbridge’s overall economic interest in the Fund was reduced from 72.3% to 69.2% upon completion of the transaction and associated financing.

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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, 2012 and 2011 have been eliminated from the Consolidated Financial Statements of Enbridge. Income taxes of $56 million and $98 million for the years ended December 31, 2012 and 2011, respectively, incurred on the related capital gains remain as charges to consolidated earnings. The Company retains the benefit of cash taxes paid in the form of increased tax basis of its investment in the underlying entities; however, accounting recognition of such benefit is not permitted until such time as the entities are sold outside of the consolidated group.

Through these transactions, which essentially resulted in a partial monetization of these assets by Enbridge through sale to noncontrolling interests (being ENF’s public shareholders), Enbridge realized a source of funds of $213 million and $210 million, as presented within Financing Activities on the Consolidated Statements of Cash Flows for the years ended December 31, 2012 and 2011, respectively. In December 2012, the Fund issued $500 million in medium-term notes. The funds from this issuance, together with its cash on hand and draws on the Fund’s committed credit facility, were used to repay the $582 million Bridge Financing to Enbridge.

Saskatchewan System Shipper Complaint

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 which will not be collected under the terms of the Settlement.

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 2013, the Company received intercompany incentive fees of $20 million (2012 - $12 million; 2011 - $10 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.

Results of Operations

Earnings for the Fund increased from $85 million for the year ended December 31, 2012 to $110 million for the year ended December 31, 2013. 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.

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Earnings from the Fund totalled $85 million for the year ended December 31, 2012 compared with $50 million for the year ended December 31, 2011. The increased earnings from the Fund reflected a full year of earnings from the assets acquired from a wholly-owned subsidiary of Enbridge in October 2011. Earnings also reflected the December 2012 transfer of Hardisty Storage Caverns, Hardisty Contract Terminals and the Greenwich, Amherstburg and Tilbury projects. Partially offsetting the earnings contributions were increased interest costs, higher business development expense and non-cash deferred income taxes.

BUSINESS RISKS

Risks for Alliance Pipeline Canada are similar to those identified for Alliance Pipeline US in the Gas Pipelines, Processing and Energy Services segment. The following risks generally relate to Green Energy and Liquids Transportation and Storage, as indicated. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks.

Green Energy

Asset Utilization

Earnings from Green Energy 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 Energy 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 Green Energy facilities could lead to decreased earnings for the Fund. Additionally, inefficiencies or interruptions of Green Energy 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 reliability of the assets on a 24-hour basis to monitor asset performance.

Liquids Transportation and Storage

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 net profit 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.

Economic Regulation

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.

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CORPORATE

EARNINGS

	2013	2012	2011
(millions of Canadian dollars)
Noverco	54	27	24
Other Corporate	(82)	(57)	(40)
Adjusted loss	(28)	(30)	(16)
Noverco - changes in unrealized derivative fair value gains/(loss)	4	(10)	-
Noverco - equity earnings adjustment	-	(12)	-
Other Corporate - changes in unrealized derivative fair value loss	(306)	(22)	(87)
Other Corporate - impact of tax rate changes	18	(11)	6
Other Corporate - foreign tax recovery	4	29	-
Other Corporate - asset impairment loss	(6)	-	-
Other Corporate - unrealized foreign exchange gains/(loss) on translation of intercompany balances, net	-	(17)	24
Other Corporate - tax on intercompany gain on sale	-	(56)	(98)
Loss attributable to common shareholders	(314)	(129)	(171)

Total adjusted loss from Corporate was $28 million for the year ended December 31, 2013 compared with adjusted losses of $30 million for the year ended December 31, 2012 and $16 million for the year ended December 31, 2011. The increase in adjusted loss reflected higher dividends paid on additional preference shares issued to fund the Company’s growth projects. Partially offsetting the increased loss were higher contributions from Noverco’s underlying assets.

Corporate earnings/(loss) were impacted by the following adjusting items:

·Noverco earnings for 2013 and 2012 included changes in the unrealized fair value gains or 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 loss on derivative financial instruments related to forward foreign exchange risk management positions.

·Other Corporate loss for each period reflected the anticipated future impact of tax rate changes.

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

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

·Other Corporate loss for 2012 and 2011 included net unrealized foreign exchange gain/(loss) on the translation of foreign-denominated intercompany balances.

·Other Corporate loss for 2012 and 2011 were impacted by tax on an intercompany gain on sale. See Sponsored Investments – Enbridge Income Fund – Crude Oil Storage and Renewable Energy Transfers for details of the transactions.

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 Limited Partnership (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 both 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. 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.

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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%.

Results of Operations

Noverco adjusted earnings increased to $54 million for the year ended December 31, 2013 from $27 million for the year ended December 31, 2012. Noverco adjusted earnings included returns on the Company’s preferred share investment as well as its equity earnings from Noverco’s underlying gas and power distribution investments. The increase in adjusted earnings was primarily attributable to higher volumes within Gaz Metro’s Quebec-based gas distribution franchise area, contributions from a full year of operations of power distribution assets acquired in mid-2012 and a small one-time gain on sale of assets of approximately $3 million. Adjusted earnings also increased slightly due to higher preferred share investment earnings. Partially offsetting the adjusted earnings increase was a lower ROE allowed by the regulator for Gaz Metro.

Noverco’s investment in power distribution operations is subject to seasonality, similar to gas distribution operations, with the majority of its annual earnings achieved during the colder months of the first quarter. This seasonal pattern heightens the effect of the earnings increase attributable to the power distribution acquisition since the 2013 results included the first quarter, whereas 2012 did not given that the acquisition took place mid-year.

Noverco adjusted earnings were $27 million for the year ended December 31, 2012 compared with $24 million for the year ended December 31, 2011 and reflected contributions from the Company’s increased preferred share investment and Noverco’s underlying gas distribution investments.

OTHER CORPORATE

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

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Preference Share Issuances

Since July 2011, the Company has issued 204 million preference shares for gross proceeds of approximately $5,127 million with the following characteristics. See Outstanding Share Data.

	Gross Proceeds	Initial Yield	Dividend 1	Per Share Base Redemption Value2	Redemption and Conversion Option Date2,3	Right to Convert Into3,4
(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

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

2The 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.

3The 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.

4Holders 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) or 2.6% (Series 8)); 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)).

5For dividends declared, see Liquidity and Capital Resources — Financing Activities.

Common Share Issuance

On April 16, 2013, the Company completed the issuance of 13 million Common Shares for gross proceeds of approximately $600 million. The proceeds were used to fund the Company’s growth projects, reduce outstanding indebtedness, invest in subsidiaries and for general corporate purposes.

Results of Operations

Other Corporate adjusted loss was $82 million for the year ended December 31, 2013 compared with an adjusted loss of $57 million for the year ended December 31, 2012. The increased loss was attributable to dividends paid on additional preference shares issued to fund the Company’s slate of growth projects. Partially offsetting increased preference share dividends were lower net Corporate segment finance costs and lower operating and administrative costs.

Other Corporate adjusted loss was $57 million for the year ended December 31, 2012 compared with an adjusted loss of $40 million for the year ended December 31, 2011 and also reflected higher dividends paid on incremental preference shares issued.

LIQUIDITY AND CAPITAL RESOURCES

The maintenance of financial strength and flexibility is fundamental to Enbridge’s growth strategy, particularly in light of the level of growth projects secured or under development. Access to timely funding from capital markets could be limited by factors outside its 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 financing plans and strategies to ensure it maintains sufficient liquidity to meet routine operating and future capital requirements. The Company targets to maintain sufficient standby liquidity to bridge fund through protracted capital markets disruptions of up to one year.

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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. The Company’s financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and it identifies potential sources of debt and equity funding alternatives, including utilization of its sponsored vehicles, with the objective of diversifying funding sources and maintaining access to low cost capital.

The Company’s financing strategy includes optimizing the funding of its enterprise-wide slate of growth projects, including through its sponsored vehicles. During 2013, several actions were taken to enhance liquidity at EEP during the next several years until its growth capital commitments are permanently funded:

·On May 8, 2013, Enbridge invested US$1.2 billion in preferred units issued by EEP. The preferred units, with a price per unit of $25 (par value), have a fixed yield of 7.5% with the rate to be reset every five years. Under the preferred units terms, quarterly cash distributions will not be payable in cash during the first eight quarters and will be added to the redemption value. Quarterly cash distributions will be payable beginning in the ninth quarter and deferred distributions are payable on the fifth anniversary or when redemption of the units takes place. The preferred units will be redeemable at EEP’s option on the five-year anniversary of the issuance and every fifth year thereafter, at par and including the deferred distribution. Earlier redemption is permitted under certain events including the ability to redeem the preferred units using the net proceeds from EEP’s equity issuances or from the sale of assets and from the issuance of debt, in equal amounts. In addition, on or after June 1, 2016, at Enbridge’s sole option, the preferred units can be converted into approximately 43.2 million common units of EEP.

·On June 28, 2013, EEP exercised options to reduce its funding and associated economic interest in each of the Eastern Access (excluding the Toledo Expansion and Line 9 Reversal and Expansion) and the Lakehead System Mainline Expansion projects by 15% to 25%. EEP retains the option to increase its economic interest back up to 40% in each of these projects within one year of their respective final project in-service dates.

·Also on June 28, 2013, a wholly-owned subsidiary of Enbridge entered into an agreement with EEP and certain of its subsidiaries to purchase accounts receivable on a monthly basis through 2016, up to a maximum of US$350 million at any one point, which was further amended to a monthly maximum of US$450 million on September 20, 2013, and again on December 2, 2013.

·On November 13, 2013, MEP, a subsidiary of EEP, completed its IPO 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 the exercise of an underwriters’ option. MEP received proceeds of approximately US$355 million from the offering. 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, through certain of its subsidiaries, holds a 2% GP interest and the remaining limited partner interest in MEP. See Sponsored Investments – Enbridge Energy Partners, L.P. – Midcoast Energy Partners, L.P. Initial Public Offering.

In accordance with its financing plan, the Company has been active in the capital markets with the following issuances during 2013:

·Corporate - $1,467 million in preference shares; $600 million in common shares; $1,888 million of medium-term notes;

·Enbridge Pipelines Inc. (EPI) - $550 million of medium-term notes;

·EGD - $400 million medium-term notes;

·EEM - US$509 million in listed shares;

·MEP - US$355 million in common units; and

·The Fund - $96 million in common units.

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In addition to these debt and equity issuances, the Company received dividends of approximately $248 million from its investment in Noverco which resulted from Noverco’s sale of Enbridge shares via a secondary offering.

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, Enbridge also significantly bolstered its committed bank credit facilities in 2013, including securement of a US$850 million facility by MEP. 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 credit facilities at December 31, 2013 and 2012.

		December 31, 2013			December 31, 2012
	Maturity Dates2	Total Facilities	Draws3	Available	Total Facilities
(millions of Canadian dollars)
Liquids Pipelines	2015	300	266	34	300
Gas Distribution	2014-2019	713	382	331	712
Sponsored Investments	2015-2018	4,781	809	3,972	3,162
Corporate	2015-2018	11,805	3,651	8,154	9,108
		17,599	5,108	12,491	13,282
Southern Lights project financing1	2014-2015	1,570	1,498	72	1,484
Total credit facilities		19,169	6,606	12,563	14,766

1Total facilities inclusive of $63 million for debt service reserve letters of credit.

2Total facilities include $35 million in demand facilities with no specified maturity date.

3Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.

Excluding project financing, the Company’s net available liquidity of $12,909 million at December 31, 2013 was inclusive of $756 million of unrestricted cash and cash equivalents and net of bank indebtedness of $338 million.

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, 2013, the Company was in compliance with all debt covenants and expects to continue to comply with such covenants.

Strong growth in internal cashflow, 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 under attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cashflow and the ratio of debt to total capital. As at December 31, 2013, the Company’s debt capitalization ratio was 58.2% compared with 60.2% as at December 31, 2012.

The Company invests a portion of its surplus cash in short-term investment grade instruments with creditworthy counterparties. Short-term investments were $85 million as at December 31, 2013 compared with $950 million as at December 31, 2012. Surplus cash at December 31, 2013 arose primarily due to pre-funding of equity requirements 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 restricted cash of $7 million related to Southern Lights project financing and cash in trust of $27 million 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, the Company had a negative working capital position of $967 million at December 31, 2013 compared with a positive working capital position of $183 million at December 31, 2012. The decrease in working capital is mainly attributable to a reduction in cash on hand combined with an increase in construction payables, both of which temporarily fund growth capital expenditures. Partially offsetting these decreases was an increase in accounts receivable in respect of the Company’s operations that have grown period-over-period.

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Despite the negative working capital as at December 31, 2013, 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, 2013, the net available liquidity totalled $12,909 million. In addition, it is anticipated that any current maturities of long-term debt will be refinanced upon maturity.

December 31,	2013	2012
(millions of Canadian dollars)
Cash and cash equivalents1	790	1,795
Accounts receivable and other2	5,021	4,026
Inventory	1,115	779
Assets held for sale3	17	-
Bank indebtedness	(338)	(479)
Short-term borrowings	(374)	(583)
Accounts payable and other4	(6,710)	(5,052)
Interest payable	(228)	(196)
Environmental liabilities	(260)	(107)
Working capital	(967)	183

1Includes short-term investments and restricted cash of amounts in trust.

2Includes Accounts receivable from affiliates.

3Net of current liabilities held for sale.

4Includes Accounts payable to affiliates.

OPERATING ACTIVITIES

Cash provided by operating activities for the year ended December 31, 2013 was $3,341 million compared with $2,874 million and $3,371 million for the years ended December 31, 2012 and 2011, respectively. 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 cash flow increase was attributable in part to the successful completion of significant projects in recent years. As discussed in Performance Overview, new Liquids Pipelines assets placed into service in 2012 and 2013, completion of Bakken Expansion in 2013 and addition of five wind farms and two solar farms between 2011 and 2013 all contributed to the increase in period-over-period operating cash flows. In addition to the new assets, the Company’s core businesses also achieved higher operating cash flows in 2013, mainly attributable to higher throughput in Liquids Pipelines, favourable market conditions in Energy Services and stronger contributions from EEP and the Fund. Partially offsetting the positive factors for 2013 were higher financing costs as the Company significantly advanced its funding plan in 2013, as well as lower dividend paid by Noverco in 2013 compared with 2012. In 2013, Noverco paid Enbridge a one-time dividend of $248 million compared with $317 million paid in 2012 upon realization of a substantial gain on the disposition of a portion of its investment in Enbridge shares.

The Company’s operating assets and liabilities fluctuate due to variations in commodity prices and sales volumes within Energy Services, the timing of tax payments, the payment of power deposits to support the Company’s growth projects, as well as general variations in activity levels within the Company’s businesses. The year-over-year increase in cash provided by operating activities in 2013 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 balance resulting from higher purchases, partially offset by increases in accounts receivable and inventory balances.

Cash provided by operating activities for 2012 was lower compared to 2011 primarily due to an unfavourable variance of $1,061 million in the changes in operating assets and liabilities. In addition, cash from operating activities during the fourth quarter of 2012 included an outflow of US$202 million related to a voluntary pre-payment of certain derivative liabilities. The payment was transacted to optimize cash management opportunities and did not alter the risk management properties of the derivative position. These cash outflows were partially offset by the favourable operating performance of the Canadian Mainline under CTS, strong volumes across all of the Company’s liquids pipelines assets and general cash growth from development projects placed in service in recent years. The dividend received from Noverco in 2012, as discussed above, also impacted the period-over-period cash flows for 2012.

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INVESTING ACTIVITIES

Cash used in investing activities was $9,431 million for the year ended December 31, 2013 compared with $6,204 million for the year ended December 31, 2012 and $5,079 million for the year ended December 31, 2011. Cash used in investing activities has increased on a year-over-year basis primarily due to additions to property, plant and equipment associated with construction of the Company’s expansion initiatives, which are described in Growth Projects – Commercially Secured Projects. A summary of additions to property, plant and equipment for the years ended December 31, 2013, 2012 and 2011 is as follows:

Year ended December 31,	2013	2012	2011
(millions of Canadian dollars)
Liquids Pipelines	4,359	1,926	906
Gas Distribution	533	445	478
Gas Pipelines, Processing and Energy Services	744	933	959
Sponsored Investments	2,565	1,886	1,157
Corporate	34	4	27
Total capital expenditures	8,235	5,194	3,527

Other notable investing activities in 2013 and 2012 included the funding of various investment and joint ventures, primarily the Texas Express NGL System and Seaway Pipeline. The Company’s investing activities for the year ended December 31, 2012 also included the acquisition of Silver State and Pipestone and Sexsmith, as well as the remaining 10% interest in Greenwich. In comparison, for the year ended December 31, 2011, the Company acquired its original 50% interest in Seaway Pipeline and increased its Noverco preferred shares investment.

FINANCING ACTIVITIES

Cash generated from financing activities was $5,070 million for the year ended December 31, 2013 compared with $4,395 million for the year ended December 31, 2012 and $2,030 million for the year ended December 31, 2011. The cash inflow from financing activities has increased over the 2011 to 2013 time frame as the Company executed its funding and liquidity plan in support of its long-term growth plan.  During 2013, the Company raised a total of $4,901 million through capital markets transactions, including $1,428 million in preference shares, $628 million in common shares and $2,845 million of medium-term notes. The Company also bolstered its liquidity in 2013 through the securement of additional credit facilities and increased draws on such facilities and commercial paper by $1,562 million in the year. 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 2013 compared with the prior year.

Financing activities also included transactions between the Company’s Sponsored Investments and their public unit holders, also referred to as noncontrolling interests. Significant transactions during the year included the IPO by MEP which raised proceeds of US$355 million. EEM and the Fund also completed issuances of units to the public of US$509 million and $96 million, respectively, in support of the growth initiatives underway by each of those entities. The Company’s sponsored vehicles also pay quarterly distributions to their public unit holders in accordance with distribution policies approved by their respective Boards.

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, 2013, dividends declared were $1,035 million (2012 - $895 million), of which $674 million (2012 - $597 million) were paid in cash and reflected in financing activities. The remaining $361 million (2012 - $297 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, 2013 and 2012, 34.9% and 33.2%, respectively, of total dividends declared were reinvested.

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On December 4, 2013, the Enbridge Board of Directors declared the following quarterly dividends with the exception of Preference Shares, Series 7, which was declared on January 15, 2014. All dividends are payable on March 1, 2014 to shareholders of record on February 14, 2014.

Common Shares	$0.35000
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 71	$0.23810

1A cash dividend of $0.2381 per share will be payable on March 1, 2014 to Series 7 preference shareholders. The regular quarterly dividend of $0.275 per share will begin in the second quarter of 2014.

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	25,532	3,184	2,324	1,911	18,113
Capital and operating leases	828	116	219	150	343
Long-term contracts	13,347	6,042	2,448	1,742	3,115
Pension obligations2	152	152	-	-	-
Total contractual obligations	39,859	9,494	4,991	3,803	21,571

1Excludes interest. Changes to the planned funding requirements are dependent on the terms of any debt refinancing agreements.

2Assumes only required payments will be made into the pension plans in 2014. Contributions are made in accordance with independent actuarial valuations as at December 31, 2013. 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 $4,455 million which are expected to be paid over the next five years.

CONTINGENCIES

United States Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Lines 6A and 6B crude oil releases. Approximately 30 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, EEP does not expect the outcome of these actions to be material. On July 2, 2012, PHMSA announced a Notice of Probable Violation related to the Line 6B crude oil release, including a civil penalty of US$3.7 million that EEP paid in the third quarter of 2012.

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EEP’s estimated cost at December 31, 2013 for the Line 6B crude oil release included an amount of US$22 million related to civil penalties EEP expects to be required to pay 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$22 million represents an estimate of the minimum amount which may be assessed, excluding costs of injunctive relief, if any, 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. Discussions with governmental agencies regarding fines and penalties are ongoing.

One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court. The parties are currently operating under an agreed interim order. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases.

As at December 31, 2013, the Company was not aware of any claims related to the Line 14 crude oil release. See Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Line 14 Crude Oil Release.

TAX MATTERS

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

OTHER LEGAL AND REGULATORY PROCEEDINGS

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

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OUTSTANDING SHARE DATA1

	Number
Preference Shares, Series A2	5,000,000
Preference Shares, Series B2,3	20,000,000
Preference Shares, Series D2,4	18,000,000
Preference Shares, Series F2,5	20,000,000
Preference Shares, Series H2,6	14,000,000
Preference Shares, Series J2,7	8,000,000
Preference Shares, Series L2,8	16,000,000
Preference Shares, Series N2,9	18,000,000
Preference Shares, Series P2,10	16,000,000
Preference Shares, Series R2,11	16,000,000
Preference Shares, Series 12,12	16,000,000
Preference Shares, Series 32,13	24,000,000
Preference Shares, Series 52,14	8,000,000
Preference Shares, Series 72,15	10,000,000
Common Shares - issued and outstanding (voting equity shares)	831,509,051
Stock Options - issued and outstanding (15,524,712 vested)	33,516,016

1Outstanding share data information is provided as at February 7, 2014.

2All 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.

3On June 1, 2017, and on June 1 every five years thereafter, the holders of Preference Shares, Series B will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series B into an equal number of Cumulative Redeemable Preference Shares, Series C.

4On March 1, 2018, and on March 1 every five years thereafter, the holders of Preference Shares, Series D will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series D into an equal number of Cumulative Redeemable Preference Shares, Series E.

5On June 1, 2018, and on June 1 every five years thereafter, the holders of Preference Shares, Series F will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series F into an equal number of Cumulative Redeemable Preference Shares, Series G.

6On September 1, 2018, and on September 1 every five years thereafter, the holders of Preference Shares, Series H will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series H into an equal number of Cumulative Redeemable Preference Shares, Series I.

7On June 1, 2017, and on June 1 every five years thereafter, the holders of Preference Shares, Series J will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series J into an equal number of Cumulative Redeemable Preference Shares, Series K.

8On September 1, 2017, and on September 1 every five years thereafter, the holders of Preference Shares, Series L will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series L into an equal number of Cumulative Redeemable Preference Shares, Series M.

9On December 1, 2018, and on December 1 every five years thereafter, the holders of Preference Shares, Series N will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series N into an equal number of Cumulative Redeemable Preference Shares, Series O.

10On March 1, 2019, and on March 1 every five years thereafter, the holders of Preference Shares, Series P will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series P into an equal number of Cumulative Redeemable Preference Shares, Series Q.

11On June 1, 2019 and on June 1 every five years thereafter, the holders of Preference Shares, Series R will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series R into an equal number of Cumulative Redeemable Preference Shares, Series S.

12On June 1, 2018 and on June 1 every five years thereafter, the holders of Preference Shares, Series 1 will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series 1 into an equal number of Cumulative Redeemable Preference Shares, Series 2.

13On September 1, 2019 and on September 1 every five years thereafter, the holders of Preference Shares, Series 3 will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series 3 into an equal number of Cumulative Redeemable Preference Shares, Series 4.

14On March 1, 2019 and on March 1 every five years thereafter, the holders of Preference Shares, Series 5 will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series 5 into an equal number of Cumulative Redeemable Preference Shares, Series 6.

15On March 1, 2019 and on March 1 every five years thereafter, the holders of Preference Shares, Series 7 will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series 7 into an equal number of Cumulative Redeemable Preference Shares, Series 8.

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QUARTERLY FINANCIAL INFORMATION1

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		(0.32	)	0.55
Dividends 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 and intercompany foreign exchange (gains)/loss	207	246		(223	)	613		843

20121	Q1	Q2	Q3	Q4		Total
(millions of Canadian dollars, except for per share amounts)
Revenues	6,532	5,445	5,676	7,007		24,660
Earnings attributable to common shareholders	261	8	187	146		602
Earnings per common share	0.34	0.01	0.24	0.19		0.78
Diluted earnings per common share	0.34	0.01	0.24	0.18		0.77
Dividends per common share	0.2825	0.2825	0.2825	0.2825		1.13
EGD - warmer/(colder) than normal weather	24	-	-	(1	)	23
Changes in unrealized derivative fair value and intercompany foreign exchange loss	110	252	93	81		536

1Revenues, Earnings attributable to common shareholders, Earnings per common share and Diluted earnings per common share for the 2012 comparative periods have been revised. See Note 4 to the December 31, 2013 Consolidated Financial Statements.

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.

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 pass through nature of these costs.

The Company actively manages its exposure to market price 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.

Included in earnings are after-tax costs of $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.

Reflected in earnings is the Company’s share of leak remediation costs associated with the Line 6B and Line 14 crude oil releases. Remediation costs of $24 million, $6 million, $5 million and $9 million were recognized in the first, second, third and fourth quarter of 2013; $2 million and $7 million in the second and third quarter of 2012, respectively. Earnings also reflected insurance recoveries associated with the Line 6B crude oil release of $6 million in the second quarter of 2013 and $24 million in the third quarter of 2012, respectively.

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In the fourth quarter of 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. 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. Also included in the fourth quarter of 2012 was a $63 million after-tax gain on recognition of a regulatory asset related to OPEB within EGD. Fourth quarter earnings for 2012 were also impacted by the impact of asset transfers between entities under common control of Enbridge, resulting in income taxes of $56 million incurred on the related capital gains.

Finally, the Company is in the midst of a substantial 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

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 $6 million for the year ended December 31, 2013 (2012 - $6 million; 2011 - $6 million).

Certain wholly-owned subsidiaries within Gas Distribution and Gas Pipelines, Processing and Energy Services have transportation commitments with several joint venture affiliates that are accounted for using the equity method. Total amounts charged for transportation services for the year ended December 31, 2013 were $222 million (2012 - $127 million; 2011 - $106 million).

Additionally, certain wholly-owned subsidiaries within Gas Pipelines, Processing and Energy Services made natural gas purchases of $99 million (2012 - $15 million; 2011 - nil) and sales of $10 million (2012 - $7 million; 2011 - $5 million) with several joint venture affiliates during the year ended December 31, 2013.

Amounts receivable from affiliates include a series of loans to Vector totalling $181 million (2012 - $178 million), included in Deferred amounts and other assets, which require quarterly interest payments at annual interest rates from 3% to 8%.

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET PRICE 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 price risk). Formal risk management policies, processes and systems have been designed to mitigate these risks.

The following summarizes the types of market price 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.

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Foreign Exchange Risk

The Company’s earnings, cash flows and OCI are subject to foreign exchange rate variability, primarily arising from its United States dollar denominated investments and subsidiaries, and certain revenues denominated in United States dollars and certain expenses denominated in Euros. The Company has implemented a policy whereby it economically hedges a minimum level of foreign currency denominated earnings exposures identified over a five-year forecast horizon. The Company may also hedge anticipated foreign currency denominated purchases or sales, foreign currency denominated debt, as well as certain equity investment balances and net investments in foreign denominated subsidiaries. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage variability in cash flows arising from its United States dollar investments and subsidiaries, and primarily non-qualifying derivative instruments to manage variability arising from certain revenues denominated in United States dollars.

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 2017 through execution of floating to fixed interest rate swaps with an average swap rate of 1.5%.

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 2018. A total of $10,419 million of future fixed rate term debt issuances have been hedged at an average swap rate of 3.8%.

The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt which stays 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.

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

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

Year ended December 31,	2013		2012		2011
(millions of Canadian dollars)
Amount of unrealized gains/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	56		(12	)	(22	)
Interest rate contracts	814		(46	)	(724	)
Commodity contracts	(9	)	52		72
Other contracts	(2	)	(3	)	6
Net investment hedges
Foreign exchange contracts	(81	)	1		(26	)
	778		(8	)	(694	)
Amount of gains/(loss) reclassified from Accumulated other comprehensive income (AOCI) to earnings (effective portion)
Foreign exchange contracts1	(8	)	1		1
Interest rate contracts2	107		(1	)	(10	)
Commodity contracts3	1		(3	)	(55	)
Other contracts4	-		2		(2	)
	100		(1	)	(66	)
Amount of gains/(loss) reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)
Interest rate contracts2	51		23		11
Commodity contracts3	(3	)	(3	)	5
	48		20		16
Amount of gains/(loss) from non-qualifying derivatives included in earnings
Foreign exchange contracts1	(738	)	120		(179	)
Interest rate contracts2	(10	)	(2	)	9
Commodity contracts3	(496	)	(765	)	280
Other contracts4	(3	)	(2	)	4
	(1,247	)	(649	)	114

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

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

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

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

LIQUIDITY RISK

Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees, as they become due. In order to manage this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available. 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. In addition, the Company maintains 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, 2013. 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.

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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. 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 these 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 media attention directed to development projects such as Northern Gateway. Potential impacts of a negative public opinion may include loss of business, legal action, increased regulatory oversight and 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;

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·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).

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 cashflows 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. 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. Early stage project risks are mitigated by early assessment of stakeholder issues to develop proactive relationships and specific action plans. 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. 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 across 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.

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. In response to the needs of commercially secured growth projects, the Company expects to require approximately 1,000 new positions over the next three years. Factors which could impact Enbridge’s ability to secure these resources include labour shortages, particularly within the Alberta market 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.

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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 risk relates to the failure 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. The Company believes operational regulation risk is mitigated by active monitoring and consulting on potential regulatory requirement changes with the respective regulators, directly or through industry associations. The Company also develops robust response plans to regulatory changes or enforcement actions. As stated previously, while the Company believes the safe and reliable operation of its assets is the best manner to adhere to existing regulations, the potential remains for regulators to make unilateral decisions that could have a non-recoverable financial impact on the Company.

Economic regulation risk relates to the risk regulators or other government entities change or reject proposed or existing commercial arrangements. These changes may adversely affect toll structures, other aspects of pipeline operations or the operations of shippers. Recently, shippers have challenged toll increases on various pipelines owned by Enbridge and some of Enbridge’s competitors. Enbridge retains dedicated professional staff and maintains strong relationships with customers, interveners and regulators to help minimize economic and regulation risk.

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 operation and insuring the Company’s assets, thereby negatively impacting earnings. The Company mitigates risk of environmental incident through its ORM Plan, which broadly aims to position Enbridge as the industry leader for system integrity, environmental and safety programs. Through the ORM Plan, the Company has expanded its maintenance, excavation and repair programs which are supported by operating and capital budgets directed to pipeline integrity. Emergency response plans, operator training and landowner education programs are included in the Company’s response preparedness. In addition, the role of Senior Vice President, Enterprise Safety & Operational Reliability was established in 2013. The new centralized role is accountable for defining and executing on an enterprise-wide vision, culture and set of integrated strategies and policies that support Enbridge’s objective of being the industry leader in process, public and personal safety, operational reliability and environmental protection.

The Company maintains comprehensive insurance coverage for its subsidiaries and affiliates which 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.

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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. Enbridge believes in a safety culture where safety incidents are not tolerated by employees and contractors and has established a target of zero incidents.

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.

Information 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. A successful cyber-attack could lead to unavailability, disruption or loss of key functionalities within the Company’s industrial control systems. As part of the Company’s ORM Plan, the Company has continued to broaden the scope of its systems security with increased mitigation activities focused on the prevention, detection and necessary response to any potential systems security incident. Additionally, to increase accountability in relation to systems security, all information technology security operations in the Company are consolidated under one leadership structure to increase consistency and compliance with the Company’s security requirements.

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 peoples 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 peoples and makes commitments to work with Aboriginal peoples 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.

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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. Please see Enbridge’s annual CSR Report, available online at http://csr.enbridge.com for further details regarding the CSR program. None of the information contained on, or connected to, Enbridge’s website is incorporated in or otherwise part of this MD&A.

CRITICAL ACCOUNTING ESTIMATES

DEPRECIATION

Depreciation of property, plant and equipment, the Company’s largest asset with a net book value at December 31, 2013 of $42,279 million (2012 - $33,318 million), or 73.4% 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 Alberta Energy Regulator and the OEB. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in 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, 2013, the Company’s significant regulatory assets totalled $1,138 million (2012 - $1,109 million) and significant regulatory liabilities totalled $1,016 million (2012 - $941 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.

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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 $101 million for the year ended December 31, 2013 (2012 - $24 million) as disclosed in Note 25, Retirement and Postretirement Benefits, to the 2013 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, 2013 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	149		22		18	2
Decrease in expected return on assets	-		8		-	-
Decrease in rate of salary increase	(30	)	(10	)	-	-

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 2013 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

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. Since then, the NEB has issued revised “base case assumptions” based on feedback from member companies. Companies have 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. and Enbridge Pipelines (Westspur) Inc. (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 are expected to begin in 2015.

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All applications by the Company will require NEB approval. The NEB has set a hearing, covering both the set-aside mechanism applications and the collection mechanism applications for both Group 1 and Group 2 companies. The hearing commenced January 14, 2014 with the decision expected in the second quarter of 2014.

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 asset retirement obligation (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.

CHANGES IN ACCOUNTING POLICIES

UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The Company commenced reporting using U.S. GAAP as its primary basis of accounting effective January 1, 2012, including restatement of comparative periods. As a Securities and Exchange Commission (SEC) registrant, the Company is permitted to use U.S. GAAP for purposes of meeting both its Canadian and United States continuous disclosure requirements.

ADOPTION OF NEW STANDARDS

Balance Sheet Offsetting

Effective January 1, 2013, the Company adopted Accounting Standards Update (ASU) 2011-11 and ASU 2013-01, which require enhanced disclosures on the effect or potential effect of netting arrangements on an entity’s financial position. As the adoption of these updates impacted disclosure only, there was no impact to the Company’s consolidated financial position for the current or prior periods presented.

Accumulated Other Comprehensive Income

Effective January 1, 2013, the Company adopted ASU 2013-02, which requires enhanced disclosures on amounts reclassified out of AOCI. As the adoption of this update impacted disclosure only, there was no impact to the Company’s consolidated financial statements for the current or prior periods presented.

Presentation of Unrecognized Tax Benefits

Effective December 31, 2013, the Company elected to early adopt ASU 2013-11, which requires presentation of unrecognized tax benefits as a reduction to a deferred tax asset for a net operating loss carryforward unless specific conditions exist. There was no material impact to the consolidated financial statements for the current or prior periods presented as a result of adopting this update.

FUTURE ACCOUNTING POLICY CHANGES

Obligations Resulting from Joint and Several Liability Arrangements

ASU 2013-04 was issued in February 2013 and provides both measurement and disclosure guidance for obligations with fixed amounts at a reporting date resulting from joint and several liability arrangements. 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, 2013 and is to be applied retrospectively.

Parent’s Accounting for the Cumulative Translation Adjustment

ASU 2013-05 was issued in March 2013 and 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. 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, 2013 and is to be applied prospectively.

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CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and United States securities law. As at December 31, 2013, an evaluation was carried out under the supervision of and with the participation of Enbridge’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of Enbridge’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by Enbridge in reports that it files with or submits to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

Management’s Report on Internal Control over Financial Reporting

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

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

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

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

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

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

Management assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2013, based on the framework established in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management concluded that the Company maintained effective internal control over financial reporting as at December 31, 2013.

During the year ended December 31, 2013, there has been no material change in the Company’s internal control over financial reporting.

The effectiveness of the Company’s internal control over financial reporting as at December 31, 2013 has been audited by PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company.

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NON-GAAP RECONCILIATIONS

	2013		2012		2011
(millions of Canadian dollars)
Earnings attributable to common shareholders	446		602		801
Adjusting items:
Liquids Pipelines
Canadian Mainline - changes in unrealized derivative fair value (gains)/loss1	268		(42	)	48
Canadian Mainline - Line 9 tolling adjustment	-		(6	)	(10	)
Canadian Mainline - shipper dispute settlement	-		-		(14	)
Regional Oil Sands System - leak remediation and long-term pipeline stabilization costs	56		-		-
Regional Oil Sands System - make-up-rights adjustment	13		-		-
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		-
Regional Oil Sands System - asset impairment write-off	-		-		8
Spearhead Pipeline - changes in unrealized derivative fair value gains1	-		-		(1	)
Gas Distribution
EGD - gas transportation costs out-of-period adjustment	56		-		-
EGD - warmer/(colder) than normal weather	(9	)	23		(1	)
EGD - tax rate changes	-		9		-
EGD - recognition of regulatory asset	-		(63	)	-
Other Gas Distribution and Storage - regulatory deferral write-off	-		-		262
Gas Pipelines, Processing and Energy Services
Aux Sable - changes in unrealized derivative fair value (gains)/loss1	-		(10	)	7
Energy Services - changes in unrealized derivative fair value (gains)/loss1	206		537		(125	)
Offshore - asset impairment loss	-		105		-
Other - changes in unrealized derivative fair value (gains)/loss1	61		-		(24	)
Sponsored Investments
EEP - leak insurance recoveries	(6	)	(24	)	(50	)
EEP - leak remediation costs	44		9		33
EEP - changes in unrealized derivative fair value (gains)/loss1	6		2		(3	)
EEP - tax rate differences/changes	3		-		-
EEP - gain on sale of non-core assets	(2	)	-		-
EEP - NGL trucking and marketing investigation costs	-		1		3
EEP - prior period adjustment	-		(7	)	-
EEP - shipper dispute settlement	-		-		(8	)
EEP - lawsuit settlement	-		-		(1	)
EEP - impact of unusual weather conditions	-		-		1
Corporate
Noverco - changes in unrealized derivative fair value (gains)/loss1	(4	)	10		-
Noverco - equity earnings adjustment	-		12		-
Other Corporate - changes in unrealized derivative fair value loss1	306		22		87
Other Corporate - impact of tax rate changes	(18	)	11		(6	)
Other Corporate - foreign tax recovery	(4	)	(29	)	-
Other Corporate - asset impairment loss	6		-		-
Other Corporate - unrealized foreign exchange (gains)/loss on translation of intercompany balances, net	-		17		(24	)
Other Corporate - tax on intercompany gain on sale	-		56		98
Adjusted earnings	1,434		1,241		1,081

1Changes in unrealized derivative fair value gains or loss are presented net of amounts realized on the settlement of derivative contracts during the applicable period.

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