UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 6-K
Report of Foreign Issuer
Pursuant to Rule 13a-16 or 15d-16
of the Securities Exchange Act of 1934
Dated March 31, 2016
Commission file number 001-15254
ENBRIDGE INC.
(Exact name of Registrant as specified in its charter)
| Canada | None | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
200, 425 – 1st Street S.W.
Calgary, Alberta, Canada T2P 3L8
(Address of principal executive offices and postal code)
(403) 231-3900
(Registrants telephone number, including area code)
Indicate by check mark whether the Registrant files or will file annual reports under cover of Form 20-F or Form 40-F.
Form 20-F ¨ Form 40-F x
Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):
Yes ¨ No x
Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by regulation S-T Rule 101(b)(7):
Yes ¨ No x
Indicate by check mark whether the Registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.
Yes ¨ No x
If “Yes” is marked, indicate below the file number assigned to the Registrant in connection with Rule 12g3-2(b):
N/A
THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 333-185591 AND 33-77022) AND FORM F-10 (FILE NO. 333-198566) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.
The following documents are being submitted herewith:
| • | Annual Report for the year ended December 31, 2015. |
| • | Annual Review for the year ended December 31, 2015. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| ENBRIDGE INC. | ||||||
| (Registrant) | ||||||
| Date: | March 31, 2016 | By: | /s/ “Tyler W. Robinson” | |||
| Tyler W. Robinson Vice President & Corporate Secretary | ||||||
Enbridge Inc. 2015 Annual Report Consistency Strength Value
“Enbridge delivered strong results in 2015, one of the most challenging years the industry has ever faced. We believe that our solid business model and approach to investing capital and operating our assets positions us to continue to deliver value for our customers, stakeholders and shareholders—today and over the longer term.” –Al Monaco, President & CEO, Enbridge Inc. What sets us apart Resiliency Our low-risk business model delivers highly predictable results in all market conditions • Minimal exposure to commodity prices, foreign exchange and interest rates • Minimal volume risk; strong, long-term contracts and billing structures • Minimal credit risk; majority of revenues underpinned by strong counterparties Financial Strength and Flexibility • Strong investment-grade credit ratings • Ample liquidity; strong access to capital Strong Supply and Demand Fundamentals • Western Canada Sedimentary Basin is short pipeline capacity • Liquids Mainline at full capacity; 2.6 million barrels per day (bpd) in January 2016 • 800,000 bpd oil sands growth expected through 2019 Industry-Leading Growth Outlook (2015 – 2019) • $26-billion commercially secured growth capital program alone drives 12 – 14 percent annual cash flow per share growth and 10 – 12 percent annual dividend growth through 2019 • Additional new development opportunities provide further potential upside to cash flow and dividend growth Forward-Looking Information This Annual Report includes references to forward-looking information. By its nature this information applies certain assumptions and expectations about future outcomes, so we remind you it is subject to risks and uncertainties that affect every business, including ours. The more significant factors and risks that might affect future outcomes for Enbridge are listed and discussed in the “Forward-Looking Information” section on page 26 of this Annual Report and also in the risk sections of our public disclosure filings, including Management’s Discussion and Analysis, available on both the SEDAR and EDGAR systems at www.sedar.com and www.sec.gov/edgar.shtml, respectively. 1 Superior Total Shareholder Return Adjusted for 2011 2-for-1 stock split 400% Enbridge Inc. S&P/TSX Composite Index 300% 3 13% CAGR 200% 100% 3 4% CAGR 2 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 1 Total Shareholder Return, assuming dividends are reinvested. 2 December 31, 2005 = zero for normalization calculation. 3 Compound Annual Growth Rate (CAGR) is the mean annual growth rate of an investment over a specified time period. 20-Year Dividend Growth Canadian dollars per share ional ddit A from Upside in $2.50 ojects t Pr men elop Dev $2.00 12% – 10 ured ec S $1.50 0.6% 1 = 1 GR CA $1.00 year 20 $0.50 $0.00 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016e 2019e We have a consistent track record of delivering annual dividend increases, and our continuing goal is to deliver superior shareholder returns through capital appreciation and dividends. 1 Compound Annual Growth Rate (CAGR) is the mean annual growth rate of an investment over a specified time period. 2015 Highlights Adjusted Earnings $1.9B Available Cash Flow from Operations (ACFFO) $3.2B Adjusted Earnings per Common Share $2.20 ACFFO per Common Share $3.72 Dividends Paid per Common Share $1.86 Growth Projects Placed into Service $8B
Contents Letter to Shareholders 2 2015 CSR Performance Highlights 12 Financial Report 16 Investor Information 172 ™ Life Takes Energy We’re committed to connecting people to the energy we all need to fuel our quality of life, and we’ve been doing so for more than 65 years. We connect people in three key ways: We Transport Energy Whether moving across town or across the country, no one is better equipped to deliver energy than Enbridge. We operate the world’s largest and most sophisticated transportation network for crude oil and liquids. We also have a growing ability to move natural gas and electricity. And we take pride in delivering it all with an unrelenting focus on safety. We Distribute Energy Our customers rely on the clean-burning natural gas we deliver to cook their food and heat their homes, water and workplaces. As owner and operator of Canada’s largest natural gas distribution company, we provide safe, reliable service to more than two million residential, commercial and industrial customers in Ontario, Quebec, New Brunswick and New York State. We Generate Energy We never stop thinking about the future of energy and sustainability, which is why we’re now a major and growing renewable energy company. Since our initial investment in 2002, we’ve invested approximately $5 billion in wind, solar, geothermal, hydropower and waste-heat power generation assets. Based on their gross generation capacity, our assets have the potential to supply more than one million homes with clean energy.
Letter to Shareholders Delivering the value you count on In a challenging environment, Enbridge delivered solid results, we continued to grow and our outlook remains positive. Enbridge performed very well in 2015 because our business model is built to weather all market conditions. Al Monaco President & Chief Executive Officer David A. Arledge Chair Board of Directors By any measure, 2015 was a difficult year for the energy business. Our customers experienced historically low oil and gas prices, and rebalancing of global supply and demand is now expected to take longer. North American energy investment 1 dropped by US$69 billion or 35 percent over the previous year and capital markets have been highly volatile. At the same time, opposition to energy infrastructure development remains a challenge–making it difficult for oil and gas producers to gain access to North American and global market pricing. New governments in Alberta and Canada were elected on platforms of change. 1 Source: Barclays E&P Spending Outlook, January 13, 2016. Even with all of these challenges, our company performed very well in 2015 because our business model is built to weather this type of environment. Most important, we achieved excellent safety and operating performance and provided reliable energy transportation for our customers. In 2015, we delivered a record $1.9 billion in adjusted earnings or $2.20 per common share; $3.2 billion in Available Cash Flow from Operations (ACFFO) or $3.72 per common share; and we increased our dividend by 33 percent. We raised $5 billion in capital and maintained our financial strength and discipline so that we remain resilient through this downturn. We put into service 14 new projects valued at $8 billion, the majority on time and on budget. We also continue to develop new opportunities that will sustain our growth and position Enbridge for the future. How we’re meeting the challenges of the current business environment In the current business environment, it’s important that we remain disciplined in how we approach the business, operate our assets and invest capital. The following principles will continue to govern our approach. Focus on safety and operational reliability. This is our Number One priority because providing safe and reliable energy 2 Enbridge Inc.
Because Safety Matters Our annual Safety Report to the Community highlights our approach to safety, how we’re performing and what we are focusing on to be even safer in the future. The Report is available online at enbridge.com/ safetyreport 2014 Enbridge Safety Report to the Community The world’s largest Enbridge moves the energy And longest crude we all count on to where we oil pipeline system, need it: our homes, businesses transporting over and communities near and far. We generate Life takes energy and our job 2.2M is to move the energy you need barrels per day. as safely as we possibly can. 1.6GW of renewable energy from wind, solar and geothermal facilities across North America. Enough to power transportation drives value for our customers, and the public expects us to protect them and the environment. It’s this priority that guides everything we do and supports our vision to be North America’s leading energy delivery company. Minimize commodity price exposure and maintain a low-risk business model. For the vast majority of our business, the transportation and distribution tolls we charge don’t depend on the price of oil and gas. Where we do have some exposure to commodity price, interest rates and foreign exchange, we closely manage those risks. In addition, our existing assets and new investments are underpinned by strong commercial structures that generate stable and predictable financial results. Ensure capital investment discipline and access to capital. We invest significant amounts of capital, so it’s important that we allocate that capital to the best projects. We also need to ensure we can effectively fund new investments from internal sources or from the capital markets. We maintain a sound balance sheet, strong investment-grade credit ratings and significant liquidity to protect against disruptions in the capital markets. Focus on competitiveness. It’s even more important in today’s difficult business environment to focus on competitiveness. A big part of that is ensuring that we understand the supply and demand fundamentals that drive our business today and in the future. It also means keeping 2015 Annual Report 3
Letter to Shareholders We’re confident in the strength and quality of our assets. Introducing ACFFO In 2015, we introduced a new financial metric–Available Cash Flow from Operations, or ACFFO–to complement adjusted EPS. ACFFO provides a greater degree of transparency into the cash flow generating capability of our businesses that drive shareholder value. We also think it’s a good way to measure our performance, especially with respect to growth potential and our capacity to pay dividends. For 2016 and going forward, ACFFO will be a key performance measure for the Company as a whole and the focus of our annual guidance. our costs in line and continually improving the effectiveness of what we do. In 2015, we closely managed our supply chain costs; reduced our workforce by five percent; and realized capital cost savings through the optimization of our Regional Oil Sands System–an initiative that will also deliver significant toll savings to our shippers. Developing our people. Our competitive advantage depends on the strength of our people. We focus on staff development at all levels of the organization and provide good opportunities for people to grow. We also make it a practice to rotate our management team members so we have a broad base of diverse and capable decision-making experience across the organization. We believe focusing on these priorities will translate into consistently strong financial performance and value creation for our shareholders over the next five years and well into the future. How we delivered value in 2015 Solid Results Our strong results in 2015 reflect the strength of our business model. Annual adjusted earnings were $1.9 billion or $2.20 per common share, a 16 percent increase over 2014. ACFFO for the full year 2015 was $3.2 billion or $3.72 per common share. That represented an increase of more than 23 percent year-over-year. Robust cash flow growth in turn supported strong dividend growth. In the first quarter, we increased our dividend by 33 percent, and announced in December a further 14 percent dividend increase effective with the first quarter of 2016. This was the st 21 consecutive year of increased dividends 4 Enbridge Inc.
for the Company. These increases reflect strong year-over-year growth and the confidence we have in our outlook. Equally important, our dividend growth has not come at the expense of our financial strength as ACFFO coverage of our dividend remains very strong at approximately two times. Safe and Reliable Operations Over the past five years, we’ve invested $5 billion in the safety and integrity of our systems. We’ve transformed our approach to safety, focusing not just on improving our systems and processes, but importantly, on how each and every member of the Enbridge team thinks about safety. We continue to strengthen our safety culture and to hold ourselves accountable to each other and to our stakeholders. We’re seeing the outcome of our efforts. We achieved solid safety performance across all of our businesses in 2015. Our total recordable injury frequency–a measure of on-the-job safety–was the lowest in the past five years. All of our business units experienced strong performance in detecting and preventing releases from our pipelines and distribution systems, 20-Year Dividend Growth Canadian dollars per share ional ddit om $2.50 A fr in Upside ojects nt me Pr op vel De % 12 – ed 10 ur $2.00 Sec $1.50 0.6% 1 1 = AGR C year $1.00 20 $0.50 $0.00 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016e 2019e 1 Compound Annual Growth Rate (CAGR) is the mean annual growth rate of an investment over a specified time period. Record Throughputs 2.6Mbpd Our liquids mainline system started 2016 on a high note, delivering a record 2.6 million barrels per day (bpd) in January. We expect this level of performance to continue because our mainline is underpinned by strong supply and demand fundamentals. We’re seeing growing volumes from Canada’s oil sands; and we offer shippers unparalleled connectivity to key refining markets. In addition to connecting them to 3.5 million bpd of market demand, we provide them with stable, economical tolls so they can achieve the best netbacks. Over the past five years, we’ve invested $5 billion in the safety and integrity of our systems. 2015 Annual Report 5
Letter to Shareholders even as we moved record volumes on our liquids systems. Being a leader in safety and protection of the environment is critical for our company’s ongoing business success. It helps us optimize system reliability and throughputs, which benefits our customers, and it helps sustain the growth of our company for the future. Execution of the Growth Plan We have placed $8 billion of projects into service since the beginning of 2015–an exceptional performance under any circumstances. Major accomplishments are highlighted below: • We continue to deliver new market access for our Liquids Pipelines customers. We’ve largely completed the Western Gulf Coast Access and Eastern Access programs and we made substantial progress with our Light Oil Market Access Program. Together, these three initiatives add 1.7 million barrels per day of incremental market access for our customers. • In Gas Distribution, we’re nearing completion of our $0.9-billion Greater Toronto Area (GTA) Project to upgrade the backbone of Enbridge Gas Distribution’s system, supporting continued customer growth and enhancing reliability. • In early 2016, we grew our Canadian natural gas midstream presence with the acquisition of the Tupper Main and Tupper West gas plants and associated pipelines in the Montney Region in northeastern B.C., one of the most attractive gas plays in North America. 1 Enbridge’s Commercially Secured Growth Projects/Estimated Costs Canadian $ billion, unless stated otherwise 2015 Liquids Pipelines Alberta Regional Infrastructure: AOC Hangingstone $0.2 Sunday Creek Terminal Expansion $0.2 Woodland Pipeline Expansion $0.7 Liquids Pipelines Market Access Initiatives: Western U.S. Gulf Coast Access: Associated Mainline Expansions $0.7 Eastern Access: Line 9 Reversal $0.7 Light Oil Market Access: Southern Access Extension US$0.6 Chicago Connectivity (Line 78) US$0.5 U.S. Associated Mainline Expansions US$1.0 Canadian Associated Mainline Expansions $0.5 Line 9 Expansion $0.1 Edmonton to Hardisty Expansion $1.6 Gas Pipelines: Beckville Cryogenic Processing Facility US$0.2 Big Foot Oil Pipeline US$0.2 Eaglebine Gathering US$0.2 Gas Distribution: 2 Other EGD growth capital $0.2 Renewable Energy: Keechi Creek Wind Project US$0.2 2016 Heidelberg Lateral Pipeline US$0.1 JACOS/Nexen Hangingstone $0.2 Line 6B Expansion US$0.3 Greater Toronto Area Project $0.9 Aux Sable Expansion $0.1 Tupper Main, Tupper West $0.5 New Creek Wind Project US$0.2 Other EGD Growth Capital $0.2 2017 Norlite Diluent Pipeline $0.9 Regional Oil Sands Optimization $2.6 Other EGD Growth Capital $0.2 2018 Rampion Offshore Wind $0.8 Stampede Lateral US$0.2 Other EGD Growth Capital $0.2 2019 Sandpiper Project US$2.6 U.S. Line 3 Replacement Program US$2.6 Canadian Line 3 Replacement Program $4.9 U.S. Mainline Phase 2 (SA to 1200) US$0.5 Other EGD Growth Capital $0.2 1 Enbridge’s commercially secured growth projects are discussed in greater detail beginning on page 35 of our Management’s Discussion and Analysis available at enbridge.com/ar2015. 2 Enbridge Gas Distribution. 6 Enbridge Inc.
• In the offshore Gulf of Mexico, where we’re one of the largest natural gas and oil transporters, the Big Foot Gas Pipeline portion of the Walker Ridge Gas Gathering System and the Big Foot Oil Pipeline were installed on the sea floor and are awaiting installation of the upstream facilities by producers. In early 2016, we completed and placed into service the Heidelberg Oil Pipeline more than three months ahead of schedule. • In Power Generation, we secured two new investments that further advance our strategy to extend and diversify our growth. The 400-MW Rampion Offshore Wind project in the UK is a natural extension of our existing wind business and a strategic entry point into an international market. The 103-MW New Creek Wind Project in West Virginia brings our net interests in renewable generating capacity to nearly 2,000 MW. Enbridge’s Major Projects (MP) group continues to be a source of competitive advantage in driving value for our customers and shareholders. MP’s execution capability combines disciplined processes, supply chain management, and the capacity and experience to get things done. Maintaining Financial Flexibility and Access to Capital We have the financial flexibility to successfully fund our growth projects in an effective and efficient manner. We generate significant cash flow net of dividends, which can be redeployed into new investments. We have a strong balance sheet and access to a variety of low-cost funding sources. In 2015, we completed our Financial Strategy Optimization, which included an increase to the Company’s targeted dividend payout, as well as the $30.4-billion drop down of Enbridge’s Canadian Liquids Offshore Wind Our recent investment in Rampion provides us with a timely and effective entry point to the European offshore wind business. The business comes with strong market fundamentals, sound commercial underpinnings and attractive returns. Half of Europe’s generating capacity will come from renewables by 2025, and offshore wind will play an important role in that growth. It is forecast that over the next decade some €100 billion will be invested in the European offshore wind industry, and more than 20 gigawatts of offshore capacity is expected to be developed in Europe over the next five years alone. Norman Wells CANA DA Zama Fort St John Fort McMurray Cheecham Kitimat Edmonton rdis Hardisty Calgary Blaine 1 Kerrobert Seattle Regina Lethbridge Rowatt Cromer Portland Gretna Great Falls Rbro Clearbrook Minot Montreal Boise Superior Ottawa 3 Toronto UNITED STATES Sarnia Bu€alo Toledo Philadelphia Denver Chicago Flanagan Las Vegas Patoka Wood Cushing River Tulsa New M Houston 2 Orleans EX IC UNITED KINGDOM London Brighton and Hove English Channel Enbridge Inc. and Enbridge Income Fund Holdings Inc. Headquarters, Calgary, Alberta, Canada Enbridge Energy Partners, L.P. and Midcoast Energy Partners, L.P. Headquarters, Houston, Texas, USA Enbridge Gas Distribution Headquarters Toronto, Ontario, Canada Liquids Systems and Joint Ventures Natural Gas Systems and Joint Ventures Power Transmission Gas Distribution Wind Assets Waste Heat Recovery Solar Assets Storage Geothermal Assets Rail Gas Assets Trucking Facility 2015 Annual Report 7
Letter to Shareholders Our continuing goal is to deliver superior shareholder returns through capital appreciation and dividends. Superior Long-Term Returns 1 Total Shareholder Return 13.7% 13.2% 11.0% 10.0% 5.3% 4.6% 4.4% 3.5% 1 year 2.3% (2015) 3 year 5 year 10 year (2013 – 2015) (2011 – 2015) (2006 – 2015) (8.3%) (20.4%) (26.0%) Enbridge Inc. S&P/TSX Composite Index Peers (median) 1 Total Shareholder Return combines share price appreciation and dividends paid to show the total return to the shareholder, expressed as an annualized percentage. Pipelines business and certain Canadian renewable energy assets to our sponsored vehicle Enbridge Income Fund. We expect our sponsored vehicle strategy will further enhance the value of our capital program by providing access to diversified sources of low-cost funding. The strategy is also expected to improve our competitiveness to pursue new investment opportunities and to extend our industry-leading growth rate beyond 2019. In 2015, the Company directly and through its affiliates collectively raised more than $1.7 billion of equity capital and $3.7 billion of term debt capital. We believe the amount of capital required to support our commercially secured growth program is very manageable given the strong cash generating capability of our assets, our diversified sources of capital, solid investment-grade credit ratings and available liquidity of $10 billion as of the end of 2015. In late February 2016, we entered into an agreement with a group of Canadian and U.S. financial institutions to issue $2.3 billion of common shares–sufficient to fulfill equity funding requirements for our consolidated commercially secured growth program through the end of 2017. We remain focused on the execution and funding of our very attractive secured growth program, while maintaining the balance sheet strength needed to support our longer-term business plans. Disappointments Although we’re pleased with our results, 2015 was not without disappointments. Persistent low prices for natural gas and natural gas liquids continue to pose headwinds for our Gas Pipelines and Processing business. In Liquids Pipelines, earnings were impacted by the nearly year-long delay in receiving regulatory approval to bring the reversed Line 9 into service. We also anticipate delays on our Line 3 Replacement and Sandpiper projects. While we were pleased to receive greater clarity from the Minnesota Public Utilities Commission in January 2016 on the regulatory process for both projects, the timeline for approval will be extended and is expected to result in a delay to the in-service dates for both projects into early 2019. Despite our financial strength and our significant accomplishments in 2015, Enbridge was impacted, along with many of our peers, by broader market reaction to commodity prices, interest rates and the continuing challenges facing the energy sector. We’ve experienced volatility in our share price and we’re disappointed Enbridge’s solid attributes were not reflected in the Company’s valuation in 2015, resulting in negative shareholder return of 20 percent. That said, our three-, five- and 10-year total shareholder return well exceeds the performance of broader market indices. How we will deliver value in the future Our commercially secured growth program alone, in combination with our existing business, is expected to deliver very attractive compound average annual growth in ACFFO per share of 12 – 14 percent over our five-year (2015 – 2019) planning horizon. 8 Enbridge Inc.
Our 50-MW Silver State North solar project in Nevada generates enough emission-free energy to serve the needs of more than 11,000 homes. We believe that the long-term “ fundamentals of energy are very strong and that our business will continue to thrive. That should readily support a base level of dividend growth in the range of 10 – 12 percent. However, cash flow and dividend growth could well exceed these levels depending on the success we have in securing and funding new growth opportunities beyond those that have been commercially secured. We will continue to evaluate new investments that diversify and extend our growth and build an opportunity set for the future. While we see further opportunities to grow our Liquids Pipelines business, we are increasingly looking to develop and grow our new platforms in renewable power generation, natural gas infrastructure and gas-fired generation, power transmission and energy marketing, as well as international opportunities to invest in energy infrastructure in select regions outside Canada and the United States. As always, investments will need to pass stringent criteria and fit within our business model. We will continue to focus most of our attention on organic growth and assets that enhance our strategic position. Given the current environment, we’ll be lowering the microscope even further to make sure that we’re deploying capital to the most optimal projects. When we decide to move on opportunities, we’ll bring those forward with executable and effective funding sources identified. There’s no doubt that the current energy environment is challenging, but we believe that the long-term fundamentals of energy are very strong and that our business will continue to thrive. We believe global energy 2015 Annual Report 9
Letter to Shareholders The majority of Enbridge Gas Distribution’s vehicle fleet runs on natural gas, thereby reducing greenhouse gas emissions. Helping Customers Conserve Energy Enbridge Gas Distribution (EGD) is helping its more than two million residential, commercial and industrial customers to use energy wisely through a wide range of demand-side management (DSM) programs, including energy-efficiency audits, financial rebates for adopting energy-saving equipment, and energy reports to help consumers better understand their energy usage. Cumulatively since 1995, EGD’s DSM programs have saved approximately 9.6 billion cubic meters of natural gas and reduced carbon dioxide equivalent emissions by 18 million tonnes, which is similar to taking approximately 3.5 million cars off the road for a year or serving approximately four million homes for a year. demand will continue to grow by about 30 percent over the next two decades, driven by global population growth, increasing urbanization to larger-scale cities and the desire for increasing living standards, particularly in developing nations. With this level of energy growth, it’s critical that we continue to develop all sources of energy supply in a sustainable way. North America has tremendous unconventional oil and gas reserves that will help meet the world’s energy needs. We also possess the skills and technology to ensure that these resources are competitive and developed sustainably. Enbridge is a big part of that in a couple of ways. First, we have a number of projects under way that will help our resources get to the best markets and to consumers who need that energy. There’s no doubt that pipelines remain the lowest cost, most efficient and safest way to transport oil and natural gas. We see continued opportunities to expand and extend our pipeline systems to help meet North America’s energy needs and contribute to energy security, as well as build connectivity to coastal markets that enable exports. Second, we see significant opportunity in the transition to a lower carbon future as we look to expand and diversify our energy businesses. It’s an opportunity we recognized more than a decade ago when we first invested in wind power generation and it’s one we’re actively pursuing today as one of Canada’s largest renewable energy companies. With our established natural gas and power generation businesses, Enbridge is well positioned to play a leadership role in the shift in the energy supply mix, and transition to a lower-carbon future. 2015 was one of the most challenging years our industry has faced in decades. Enbridge has persevered–and we’re well positioned to withstand the current turbulent market environment. 10 Enbridge Inc.
Acknowledgements Enbridge has a highly capable and energetic team of people with a proven track record of delivering value to customers and shareholders alike. We thank them for their outstanding work in 2015 in building the Company and putting it in a strong position for future growth. In 2015, Lorne Braithwaite and Charles Schultz retired from the Board and we thank them for their valuable contribution to the Board’s deliberations over the years. We also welcomed to the Board Rebecca Roberts, who was President of Chevron Pipe Line Company from 2006 to 2011 and President of Chevron Global Power Generation from 2003 to 2006. We’re striving for leadership in safety and environmental stewardship. In a turbulent environment, Enbridge’s reliable and proven business model sets us apart 2015 was a year of challenge and change for the energy sector. As we begin 2016, the energy landscape continues to evolve–driven by changing dynamics of supply and demand, and shaped by the imperative to protect our environment while meeting our global energy needs. This isn’t new to us. We’re managing our business to weather these kinds of tough conditions, we’re very mindful of current market conditions and we will remain vigilant. You can read our 2015 Annual Report online at enbridge.com/ar2015 We’re confident in the strength and quality of our assets, and we believe our approach–and the principles we’ve adhered to over the years–uniquely position Enbridge to manage through these turbulent times and to continue to deliver the value you count on today and over the long term. Al Monaco President & Chief Executive Officer March 8, 2016 David A. Arledge Chair Board of Directors 2015 Annual Report 11
2015 CSR Performance Highlights Corporate Social Responsibility The world isn’t standing still, and neither are we. We’re working to meet the high standards the public expects of us—putting safety and environmental protection first; being open and transparent about our performance; providing good jobs to a talented workforce; and striving to build strong relationships with communities, Aboriginal and Native American groups and stakeholders everywhere we operate. We’re also very aware that as a North American leader in energy infrastructure systems that deliver oil, natural gas and renewable energy, we are uniquely positioned to help bridge the transition to a lower-carbon future. Energy systems are changing and so are we. But one thing won’t change. We will keep fuelling people’s quality of life, because life takes energy. Presented here is a summary of our 2015 CSR performance. You can read our entire 2015 CSR & Sustainability Report online at csr.enbridge.com The report covers the governance, social, environmental and economic issues that are most important to our stakeholders, our business today and our strategic priorities. Every year, we work to make our sustainability reporting more robust, transparent and useful for all readers, internal and external to the company. It’s important to us because sharing our sustainability successes, challenges and opportunities is one of the ways we hold ourselves accountable for our performance on the social and environmental issues that are integral to the future of our business and everyone who depends on us. The year-long sustainability reporting process that underpins the development of content for this report also helps us identify what’s next and how we can do better in the future. 2015 at a Glance Liquids Pipelines (LP) System Integrity and Leak Detection $787million 1 In 2015, we invested more than $787 million in systems integrity and leak detection programs for our liquids systems in Canada and the U.S. 1 Includes Canada and U.S. dollar amounts 141 pipeline inspections in 2015 across our LP system >2.8B barrels of crude oil and liquids delivered by LP <280 bbls spilled in 2015, of which 95 percent were contained within our facilities 17.2B bbls is the amount of crude oil and liquids our LP system delivered from 2006 to 2015, with a safe delivery percentage of 99.9995 Renewable + Alternative Energy $5B invested in renewable and alternative energy projects since 2002 Nearly 2,800MW of gross generating capacity (Enbridge Inc. and subsidiaries’ interests: 2,000 MW) The full CSR Report is available at csr.enbridge.com 12 Enbridge Inc.
Based on gross generation figures, our portfolio of renewable power assets has the potential to supply more than one million homes with clean energy. Solar Gross Capacity 150MW 1 Our Interest 150MW Geothermal Gross Capacity 23MW 1 Our Interest 9MW Waste Heat Recovery Gross Capacity 34MW 1 Our Interest 17MW Hydro Power Gross Capacity 2MW 1 Our Interest 1MW 2015 Annual Report 13
2015 CSR Performance Highlights Fitness of Enbridge’s Liquids Systems and Leak Detection Our goal is to achieve industry leadership in the safety and reliability of our pipelines and facilities, and protection of the environment. Asset Integrity and Reliability LP In-Line Inspection Runs 211 167 141 13 14 15 Having invested billions of dollars in the safety and reliability of our systems over the past five years, we are beginning to decrease the number of the in-line and other inspections that we conduct. However, our commitment to the safety of our systems is not decreasing. Advancements in predictive (reliability) modeling, data analysis and improved efficiency in carrying out our activities are enabling us to continually enhance the safety and integrity of our systems while optimizing our time and costs. LP Spills, Leaks and Releases Over the past decade, our LP system delivered 17.2 billion barrels of crude oil and liquids with a safe delivery record of 99.9995 percent. Summary Profile of 2015 LP Spills • One incident had a volume of 100 barrels or greater. • In 38 of the 45 incidents, a total of 264 barrels of oil were spilled and contained within our facilities. • In the other seven incidents, a total of 15 barrels were spilled on our pipeline rights-of-way outside our facilities. LP Spills History (2010 – 2015) 114 80 77 74 58 45 34,122 10,178 2,284 4,298 2,921 279 10 11 12 13 14 15 barrels spills, leaks and releases Energy & Climate Change We believe the world must find new ways to meet increasing demand for energy from a growing global population while limiting the greenhouse gas (GHG) emissions that cause climate change. GHG Emissions and Energy Consumption 1 2014 GHG Emissions Tonnes of carbon dioxide equivalent (tCO e) 2 4M 2 . 94 3 3M 99 . 05 87 . 3 2 . 69 2 . 2M 2 . 28 2 1M 0 2012 2013 2014 2012 2013 2014 3 Direct GHG Emissions Indirect GHG Emissions 1 2015 GHG emissions data will be available in mid 2016. 2 Increase is largely due to greater electricity use by LP due to increased delivery volumes. 3 Indirect GHG emissions are those that result from an organization’s activities, but that occur at sources not owned or controlled by the organization. 1 2014 Energy Consumption Gigajoules (GJ) 50M 40M 4 42 . . 4 39 . 2 30M 34 20M 2 . 4 21 . 0 . 3 16 17 10M 0 2012 2013 2014 2012 2013 2014 Fuel Electricity 1 2015 energy consumption data will be available in mid 2016. 2 Increase is largely due to greater electricity use by LP due to increased delivery volumes. 14 Enbridge Inc.
Human Health & Safety We are committed to ensuring that everyone returns home safely at the end of the day, and that our assets are operated safely. Our commitment is based on caring for our employees, contractors, customers, communities and the environment. Recordable and Lost-Days Injuries As we strive to achieve industry leadership in pipeline system integrity, process safety and environmental responsibility, we also strive to be a leader in human health and safety. 2013 1.14 0.17 0/1 2014 0.94 0.11 1/1 0.66 0.12 2015 0/0 Recordable Injuries Lost-Days Injuries Fatal Incidents for 200,000 employee per 200,000 employee Employees/ hours worked hours worked Contractors Supply Chain and Procurement We recognize that our supply chain plays a key role in helping fuel people’s quality of life, which is why we are building strong relationships with our suppliers and developing a comprehensive and consistent approach to supply chain management. 96 percent of steel pipe purchased by our Major Projects group was made of 100 percent recycled content (212,000 tonnes) 4% 96% Economic Impact and Benefits In 2015, we invested over $19 million in more than 750 charitable, non-profit and community organizations, and more than $63 million on procuring goods and services from Aboriginal businesses, contractors and suppliers. Through the taxes we pay to governments and the salaries we pay to employees and contractors—and through our capital and operating & administration expenses—we also have a positive economic impact on the countries and communities in which we operate. Economic Benefits Canada US 1 Taxes Paid to Governments $266M $341M Base Salaries $631M US$227M Capital Expenses $4.1B $3.2B Operating & Administration Expenses $1.8B $2.4B 1 In Canada, payments to governments include property taxes, income taxes and other taxes. In the U.S., they include property taxes, sales & use taxes, income taxes and other taxes. 2015 Annual Report 15
Enbridge Inc. Financial Report Management’s Discussion & Analysis 18 Overview 19 Canadian Restructuring Plan 20 United States Restructuring Plan 21 Performance Overview 27 Non-GAAP Measures 28 Corporate Vision and Strategy 31 Industry Fundamentals 35 Growth Projects—Commercially Secured Projects 37 Liquids Pipelines 38 Gas Distribution 39 Gas Pipelines, Processing and Energy Services 43 Sponsored Investments 47 Other Announced Projects Under Development 48 Liquids Pipelines 59 Gas Distribution 62 Gas Pipelines, Processing and Energy Services 70 Sponsored Investments 83 Corporate 86 Liquidity and Capital Resources 91 Outstanding Share Data 92 Quarterly Financial Information 93 Related Party Transactions 94 Risk Management and Financial Instruments 99 Critical Accounting Estimates 101 Changes in Accounting Policies 103 Controls and Procedures 16 Enbridge Inc. 2015 Annual Report
Consolidated Financial Statements 104 Management’s Report 105 Independent Auditor’s Report 107 Consolidated Statements of Earnings 108 Consolidated Statements of Comprehensive Income 109 Consolidated Statements of Changes in Equity 110 Consolidated Statements of Cash Flows 111 Consolidated Statements of Financial Position Notes to the Consolidated Financial Statements 112 1. General Business Description 113 2. Summary of Significant Accounting Policies 119 3. Changes in Accounting Policies 121 4. Segmented Information 123 5. Financial Statement Effects of Rate Regulation 125 6. Acquisitions and Dispositions 127 7. Accounts Receivable and Other 127 8. Inventory 128 9. Property, Plant and Equipment 129 10. Variable Interest Entities 130 11. Long-Term Investments 132 12. Restricted Long-Term Investments 132 13. Deferred Amounts and Other Assets 133 14. Intangible Assets 133 15. Goodwill 134 16. Accounts Payable and Other 134 17. Debt 136 18. Other Long-Term Liabilities 136 19. Asset Retirement Obligations 136 20. Noncontrolling Interests 139 21. Share Capital 141 22. Stock Option and Stock Unit Plans 144 23. Components of Accumulated Other Comprehensive Income/(Loss) 145 24. Risk Management and Financial Instruments 156 25. Income Taxes 158 26. Retirement and Postretirement Benefits 163 27. Other Income/(Expense) 163 28. Severance Costs 163 29. Changes in Operating Assets and Liabilities 164 30. Related Party Transactions 164 31. Commitments and Contingencies 167 32. Guarantees 167 33. Subsequent Event 168 Glossary 170 Five-Year Consolidated Highlights 172 Investor Information 17
Management’s Discussion & Analysis This Management’s Discussion and Analysis (MD&A) dated February 19, 2016 should be read in conjunction with the audited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) for the year ended December 31, 2015, prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com. Overview Enbridge, a Canadian Company, is a North American leader in delivering energy. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids transportation system. The Company also has significant and growing involvement in natural gas gathering, transmission and midstream businesses. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company and provides distribution services in Ontario, Quebec, New Brunswick and New York State. As a generator of energy, Enbridge has interests in nearly 2,800 megawatts (MW) (2,000 MW net) of renewable and alternative energy generating capacity which is operating, secured or under construction, and the Company continues to expand its interests in wind, solar and geothermal power. Enbridge employs nearly 11,000 people, primarily in Canada and the United States. The Company’s activities are carried out through five business segments: Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services; Sponsored Investments; and Corporate, as discussed below. Liquids Pipelines Until August 31, 2015, Liquids Pipelines consisted of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines and terminals in Canada and the United States, including Canadian Mainline, Regional Oil Sands System, Seaway Crude Pipeline System (Seaway Pipeline), Flanagan South Pipeline (Flanagan South), Southern Lights Pipeline, Spearhead Pipeline and Feeder Pipelines and Other. Effective September 1, 2015, under the Canadian Restructuring Plan described below, Enbridge transferred to the Fund Group (comprising Enbridge Income Fund (the Fund), Enbridge Commercial Trust (ECT), Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP), the Canadian Mainline, Regional Oil Sands System, the Canadian portion of the Southern Lights Pipeline and certain residual rights and/or obligations relating to certain terminal and storage assets. The performance of these transferred assets is reported under the Sponsored Investments segment from the date of transfer. Gas Distribution Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD), which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick. Total Assets (millions of Canadian dollars) 84,664 72,857 57,568 46,800 41,130 11 12 13 14 15 ? Liquids Pipelines ? Gas Distribution ? Gas Pipelines, Processing and Energy Services ? Sponsored Investments ? Corporate 18 Enbridge Inc. 2015 Annual Report
Gas Pipelines, Processing and Energy Services Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines, gathering and processing facilities and the Company’s energy services businesses, along with renewable energy and transmission facilities. Effective September 1, 2015, under the Canadian Restructuring Plan described below, Enbridge transferred to the Fund Group certain Canadian renewable energy assets which are reported under the Sponsored Investments segment from the date of transfer. Investments in natural gas pipelines include the Company’s interests in the Vector Pipeline (Vector) and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in Aux Sable, a natural gas extraction and fractionation business located near the terminus of the Alliance Pipeline and Canadian Midstream assets located in northeast British Columbia and northwest Alberta. The energy services businesses undertake physical commodity marketing activity and logistical services, oversee refinery supply services and manage the Company’s volume commitments on Alliance Pipeline, Vector and other pipeline systems. Sponsored Investments Sponsored Investments includes the Company’s overall 89.2% economic interest in the Fund Group. Also included within Sponsored Investments is the Company’s 35.7% economic interest in Enbridge Energy Partners, L.P. (EEP) and Enbridge’s interests in both the Eastern Access and Lakehead System Mainline Expansion projects held through Enbridge Energy, Limited Partnership (EELP). Enbridge, through its subsidiaries, manages the day-to-day operations of and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities. As a result of the Canadian Restructuring Plan, as discussed below, effective September 1, 2015, the Fund Group’s primary operations include its liquids pipelines business, which includes the Canadian Mainline and Regional Oil Sands System, its renewable power generation assets and a natural gas transmission business through its 50% interest in Alliance Pipeline. EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines, including the Lakehead Pipeline System (Lakehead System), which is the United States portion of the Enbridge mainline system, and transports, gathers, processes and markets natural gas and NGL. Corporate Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, general corporate investments and financing costs not allocated to the business segments. Canadian Restructuring Plan On September 1, 2015, Enbridge announced it had completed the transfer of its Canadian Liquids Pipelines business, held through Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines (Athabasca) Inc. (EPAI), and certain Canadian renewable energy assets to EIPLP, in which the Fund has an indirect interest, for aggregate consideration of $30.4 billion plus incentive distribution and performance rights (the Canadian Restructuring Plan or the Transaction). The Transaction is a key component of Enbridge’s Financial Optimization Strategy introduced in December 2014, which included an increase in the Company’s targeted dividend payout. It advances the Company’s sponsored vehicle strategy and supports Enbridge’s 33% dividend increase effective March 1, 2015 and a further 14% dividend increase effective March 1, 2016. The Transaction is expected to provide Enbridge with an alternate source of funding for its enterprise wide growth initiatives and enhance its competitiveness for new organic growth opportunities and asset acquisitions. In conjunction with the execution of the Transaction, Enbridge adopted a supplemental cash flow metric, available cash flow from operations (ACFFO), which was introduced in the second quarter of 2015 and is now a part of the Company’s normal course annual and quarterly reporting of financial performance and in the provision of guidance. ACFFO is used to assess the performance of the Company’s base business and the impact of its growth program. The Company also started expressing its dividend payout range as a percentage of ACFFO rather than adjusted earnings and has established a long-term target payout of 40% to 50% of ACFFO. Consideration Upon closing of the Transaction, Enbridge received $18.7 billion of units in the Fund Group, comprised of approximately $3 billion of ordinary units of the Fund and $15.7 billion of common equity units of EIPLP, which at the time of the Transaction was an indirect subsidiary of the Fund. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion. In addition, a portion of the consideration to be received by Enbridge over time will be in the form of units which carry Temporary Performance Distribution Rights (TPDR). The TPDR are designed to allow Enbridge to capture increasing value from the secured growth embedded within the transferred businesses; however, the cash flows derived from this incentive mechanism will be deferred (until such time as the units become convertible to a class of cash paying units in the fourth year after issuance). Enbridge will continue to earn a base incentive fee from the Fund Group through management and incentive fees and Incentive Distribution Rights (IDR), which entitle it to receive 25% of the pre-incentive distributable cash flow above a base distribution threshold of $1.295 per unit, adjusted for a tax factor. The base Management’s Discussion & Analysis 19
incentive fee is paid out of ECT. Distributions over $1.890 per unit will be paid out of EIPLP. In addition, Enbridge received the TPDR, a distribution equivalent to 33% of pre-incentive distributable cash flow above the base distribution of $1.295 per unit. The TPDR are paid in the form of Class D units of EIPLP and will be issued each month until the later of the end of 2020 or 12 months after the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program) enters service. The Class D unitholders receive a distribution each month equal to the per unit amount paid on Class C units of EIPLP, but to be paid in kind in additional Class D units. Each Class D unit is convertible into a cash paying Class C unit of EIPLP in the fourth year after its issuance. The Fund units, Class A units of EIPLP and the EIPLP Class C units will pay a per unit cash distribution equivalent to the per unit cash distribution that the Fund pays on its units held by Enbridge Income Fund Holdings Inc. (ENF). The Fund units, EIPLP’s Class C units and existing preferred units of ECT also include an exchange right whereby they may be converted into common shares of ENF on a one-for-one basis. Financing Plan To acquire an increasing ownership interest in the Fund Group, the financing plan contemplates the issuance by ENF of $600 million to $800 million of public equity per year in one or more tranches through 2018 to fund an increasing investment in the Canadian Liquids Pipelines business. Enbridge has agreed to backstop the equity funding required by ENF to undertake the growth program embedded in the assets it acquired in the Transaction. The amount of public equity issued by ENF will be adjusted as necessary to match its capacity to raise equity funding on favourable terms. On November 6, 2015, ENF successfully completed an equity offering of 21.5 million common shares at a price of $32.60 per share for gross proceeds of $700 million. Concurrent with the closing of the equity offering, Enbridge subscribed for 5.3 million common shares at a price of $32.60 per share, for total proceeds of $174 million, on a private placement basis to maintain its 19.9% ownership interest in ENF. Development Opportunities The Canadian Liquids Pipelines business is expected to have future organic growth opportunities beyond the current inventory of secured projects. The Fund Group has a first right to execute any such projects that fall within the footprint of the Canadian Liquids Pipelines business. Should the Fund Group choose not to proceed with a specific growth opportunity, Enbridge may pursue such opportunity. Economic Interest Upon closing of the Transaction, Enbridge’s overall economic interest in the Fund Group, including all of its direct and indirect interests in the Fund Group, was 91.9%. Upon completion of the $700 million common share issuance discussed above, Enbridge’s economic interest decreased to 89.2%. As ENF executes on its financing plan and increases its ownership in the Fund Group over time, Enbridge’s economic interest is expected to decline to approximately 80% by the end of 2018. Fund Governance Enbridge continues to act as the manager of the Fund Group and operator and commercial developer of the Canadian Liquids Pipelines business. This will ensure continuity of management and operational expertise, with an ongoing commitment to the safe and reliable operation of the system. As a result of its significant ownership interest, Enbridge has the right to appoint a majority of the Trustees of the Board of ECT for as long as the Company holds a majority economic interest in the Fund Group. A standing conflicts committee has been established to review certain material transactions and arrangements where the interests of Enbridge, or its affiliates, and the relevant entity in the Fund Group, or its affiliates, come into conflict. United States Restructuring Plan In 2015, a review of a potential transfer of Enbridge’s United States liquids pipelines assets to EEP determined that conditions in the master limited partnership market do not support a large scale drop down at this time. EEP has over US$6 billion of secured growth projects expected to come into service through 2019 and options to increase its economic interest in projects that are jointly funded by Enbridge and EEP. Enbridge has a large inventory of United States liquids pipelines assets which are well suited to EEP and it continues to evaluate opportunities to generate value through selective drop downs of ownership interests or assets of approximately $500 million annually to EEP depending on market conditions. 20 Enbridge Inc. 2015 Annual Report
Performance Overview Three months ended Year ended December 31, December 31, 2015 2014 2015 2014 2013 (millions of Canadian dollars, except per share amounts) Earnings attributable to common shareholders 1 Liquids Pipelines 36 19 (224) 463 427 Gas Distribution 46 69 222 213 129 1 Gas Pipelines, Processing and EnergyServices 44 185 218 571 (68) 1 Sponsored Investments 297 140 479 419 268 Corporate (45) (325) (732) (558) (314) Earnings/(loss) attributable to common shareholders from continuing operations 378 88 (37) 1,108 442 Discontinued operations – Gas Pipelines, Processing and Energy Services – – – 46 4 378 88 (37) 1,154 446 Earnings/(loss)percommonshare 0.44 0.11 (0.04) 1.39 0.55 Dilutedearnings/(loss)percommonshare 0.44 0.10 (0.04) 1.37 0.55 2 Adjusted earnings 3 Liquids Pipelines 64 199 691 858 770 Gas Distribution 58 68 210 177 176 3 Gas Pipelines, Processing and EnergyServices (5) 30 89 136 203 3 Sponsored Investments 369 123 859 429 313 Corporate 8 (11) 17 (26) (28) 494 409 1,866 1,574 1,434 2 Adjusted earnings per common share 0.58 0.49 2.20 1.90 1.78 Cash flow data Cash provided by operating activities 806 656 4,571 2,547 3,341 Cash used in investing activities (2,296) (3,737) (7,933) (11,891) (9,431) Cash provided by financing activities 1,457 3,221 2,973 9,770 5,070 4 Available cash flow from operations Available cash flow from operations 876 610 3,154 2,506 2,527 Dividends Common share dividends declared 401 297 1,596 1,177 1,035 Dividends paid per common share 0.465 0.350 1.86 1.40 1.26 1 Revenues Commodity sales 6,074 6,192 23,842 28,281 26,039 Gas distribution sales 672 835 3,096 2,853 2,265 Transportation and other services 2,168 1,770 6,856 6,507 4,614 8,914 8,797 33,794 37,641 32,918 Total assets 84,664 72,857 84,664 72,857 57,568 Total long-term liabilities 51,511 42,306 51,511 42,306 28,277 1 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group within the Sponsored Investments segment (described above under Canadian Restructuring Plan). Losses from the Canadian Liquids Pipelines assets prior to the date of transfer of $403 million in the year ended December 31, 2015 (2014 – earnings of $320 million; 2013 – earnings of $261 million) and earnings from the Canadian renewable energy assets within the Gas Pipelines, Processing and Energy Services segment prior to the date of transfer of $1 million in the year ended December 31, 2015 (2014 – loss of $2 million; 2013 – loss of $55 million), have not been reclassified into the Sponsored Investments segment for presentation purposes. Additionally, a loss of $29 million and earnings of $6 million for the three months ended December 31, 2014, related to Liquids Pipelines assets and Gas Pipelines, Processing and Energy Services assets, respectively, have not been reclassified into the Sponsored Investments segment for presentation purposes. 2 Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures see page 27. 3 Adjusted earnings from the Canadian Liquids Pipelines assets prior to the date of transfer of $508 million in the year ended December 31, 2015 (2014 – $688 million; 2013 –$631 million) and adjusted earnings from the Canadian renewable energy assets within the Gas Pipelines, Processing and Energy Services segment prior to the date of transfer under the Canadian Restructuring Plan of $6 million in the year ended December 31, 2015 (2014 – loss of $3 million; 2013 – loss of $4 million), have not been reclassified into the Sponsored Investments segment for presentation purposes. Additionally, adjusted earnings of $146 million and $1 million, for the three months ended December 31, 2014, related to Liquids Pipelines assets and Gas Pipelines, Processing and Energy Services assets, respectively, have not been reclassified into the Sponsored Investments segment for presentation purposes. 4 ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in regulatory assets and liabilities and environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. ACFFO is a non-GAAP measure that does not have any standardized meaning prescribed by GAAP –see Non-GAAP Measures. Management’s Discussion & Analysis 21
Earnings/(Loss) Attributable to Common Shareholders Loss attributable to common shareholders was $37 million ($0.04 loss per common share) for the year ended December 31, 2015 compared with earnings of $1,154 million ($1.39 earnings per common share) for the year ended December 31, 2014 and earnings of $446 million ($0.55 earnings per common share) for the year ended December 31, 2013. As discussed below in Performance Overview – Adjusted Earnings, the Company has continued to deliver strong earnings growth from operations over the course of the last three years. However, the positive impact of this growth and the comparability of the Company’s earnings are impacted by a number of unusual, non-recurring or non-operating factors that are listed in Non-GAAP Reconciliations and discussed in the results for each reporting segment, the most significant of which are changes in unrealized derivative fair value gains and losses. The Company has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks which create volatility in short-term earnings. Over the long term, Enbridge believes its hedging program supports the reliable cash flows and dividend growth upon which the Company’s investor value proposition is based. The comparability of the Company’s year-over-year operating results was also impacted by the transfer of assets between entities under common control of Enbridge in connection with the Canadian Restructuring Plan which resulted in $351 million of one-time charges, mainly related to the de-designation of interest rate hedges and a write-off of a regulatory asset in respect of taxes. In addition, the 2015 loss attributable to common shareholders reflects a goodwill impairment charge of $440 million ($167 million after-tax attributable to Enbridge) recognized in the second quarter of 2015 related to EEP’s natural gas and NGL businesses. The prolonged decline in commodity prices has reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL pipelines and processing systems, which EEP holds directly and indirectly through its partially-owned subsidiary, Midcoast Energy Partners, L.P. (MEP). Loss for 2015 and earnings for 2014 were also negatively impacted by taxes recognized on the transfer of assets between entities under common control of Enbridge. Intercompany gains realized as a result of these transfers for both years have been eliminated for accounting purposes. However, as these transactions involved the sale of partnership units, all tax consequences have remained in consolidated earnings and resulted in charges of $39 million and $157 million in 2015 and 2014, respectively. Fourth quarter performance drivers were largely consistent with year-to-date trends and earnings continued to be impacted by changes in unrealized fair value derivative and foreign exchange gains and losses. Aside from the operating factors discussed in Performance Overview – Adjusted Earnings, factors unique to the fourth quarter of 2015 included the impact of employee severance costs in relation to the Company’s enterprise-wide reduction of workforce, which resulted in a net charge of $25 million to earnings across business segments. Earnings/(Loss) Attributable to Common Shareholders (millions of Canadian dollars) 2 1,555 2 1,321 1 1,154 1 930 1 2 801 2 700 1 615 602 1 446 1 (37) 06 07 08 09 10 11 12 13 14 15 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. 22 Enbridge Inc. 2015 Annual Report
Adjusted Earnings The Company’s investor value proposition is built upon visible growth, a reliable business model and a growing income and cash flow stream, supported by a rigorous focus on safe and reliable operations and a disciplined approach to investment and project execution. The Company has consistently delivered on this proposition, growing adjusted earnings from $1.78 per common share in 2013 to $1.90 per common share in 2014 and $2.20 per common share in 2015. This growth is a reflection of the underlying strength of Enbridge’s existing asset portfolio combined with the continuing execution of its large growth capital program, which resulted in a number of new assets placed into service over this period. The Company’s current five year plan includes approximately $26 billion of commercially secured growth projects of which approximately $8 billion were brought into service in 2015. The remaining $18 billion are expected to be completed and placed into service between 2016 and 2019. Following the close of the Canadian Restructuring Plan on September 1, 2015, adjusted earnings from the Canadian Mainline and Regional Oil Sands System are no longer reported in the Liquids Pipeline segment, but are captured in the results of the Fund Group which are reported within Sponsored Investments. Growth in consolidated adjusted earnings was largely driven by stronger contributions from the Canadian Mainline, primarily from higher throughput that resulted from strong oil sands production in western Canada combined with strong downstream refinery demand, as well as ongoing efforts by the Company to optimize capacity utilization and to enhance scheduling efficiency with shippers. These positive factors were partially offset by a lower year-over-year average Canadian Mainline International Joint Tariff (IJT) Residual Benchmark Toll. In 2015, the Company also benefitted from the full-year of earnings from the Flanagan South and Seaway Twin pipelines, both of which commenced in late 2014. Adjusted earnings from Regional Oil Sands System, however, decreased in 2015 due to a reduction in contracted volumes on the Athabasca Mainline. The past two years also reflected positive contributions from EEP mainly due to higher throughput and tolls on EEP’s liquids businesses, as well as contributions from new assets placed into service in 2014 and 2015, the most prominent being the expansion of the Company’s mainline system completed in July 2015 and the replacement and expansion of Line 6B completed in 2014. EGD, which operates under a five-year customized Incentive Rate Plan (IR Plan) approved in 2014, generated higher adjusted earnings in 2015 primarily attributable to an increase in distribution charges that resulted from an increased asset base, as well as customer growth during the year in excess of expectations embedded in rates. Within Gas Pipelines, Processing and Energy Services, lower fractionation margins and the loss of a producer processing contract at the Palermo Conditioning Plant have contributed to lower Aux Sable earnings over the past two years. Partially offsetting the decrease in 2015 were higher take-or-pay fees on Canadian Midstream assets and higher contributions from Energy Services. Energy Services benefitted from more favourable tank management opportunities in the first half of 2015 resulting from strong refinery demand for blended crude oil feedstock, partially offset by the effects of less favourable conditions which persisted over the past two years in certain markets accessed by committed transportation capacity involving unrecovered demand charges. Within the Corporate segment, Other Corporate adjusted loss for the year ended December 31, 2015 decreased compared with 2014, reflecting lower net Corporate segment finance costs in the first half of 2015 and lower income taxes, partially offset by higher preference share dividends reflecting additional preference shares issued in 2014 to fund the Company’s growth capital program. With respect to the fourth quarter of 2015, many of the annual trends discussed above were also the factors in driving adjusted earnings growth over the fourth quarter of 2014. Within Gas Distribution, although EGD adjusted earnings increased on a year-over-year basis, the timing of higher income taxes and operating and administrative expenses recorded in the fourth quarter of 2015 drove a decrease in quarter-over-quarter adjusted earnings. In Energy Services, the absence of tank Adjusted Earnings (millions of Canadian dollars) 1 1,866 1 1 1,434 1,574 1 1 1,241 1 1,081 2 855 963 2 2 2 593 637 677 06 07 08 09 10 11 12 13 14 15 1 Financial information has been extracted from financial statements prepared in accordance with U.S. GAAP. 2 Financial information has been extracted from financial statements prepared in accordance with Canadian GAAP. Management’s Discussion & Analysis 23
management opportunities in the fourth quarter combined with conditions in certain markets as noted above resulted in an adjusted loss in the fourth quarter of 2015 compared with adjusted earnings in the comparable 2014 period. Available Cash Flow from Operations ACFFO was $876 million for the three months ended December 31, 2015 compared with $610 million for the three months ended December 31, 2014. ACFFO was $3,154 million for the year ended December 31, 2015 compared with $2,506 million for the year ended December 31, 2014. The Company experienced strong quarter-over-quarter and year-over-year growth in ACFFO which was driven by the same factors as those impacting adjusted earnings across the Company’s various businesses, as discussed in Adjusted Earnings above. Also contributing to the period-over-period increase in ACFFO were lower maintenance capital expenditures in 2015 compared with the corresponding 2014 periods. Over the last few years, the Company has made a significant investment in the ongoing support, maintenance and integrity management of its pipelines and other infrastructure and in the preservation of the service capability of its existing assets. The period-over-period decrease in maintenance capital expenditures is due to the completion of specific maintenance programs in 2014. The Company plans to continue to invest in its maintenance capital program to support the safety and reliability of its operations. The period-over-period increase in ACFFO was partially offset by distributions to noncontrolling interests in EEP and Enbridge Energy Management, L.L.C. (EEM) and to redeemable noncontrolling interests in the Fund. Distributions were higher in 2015 compared with the distributions in 2014 mainly as a result of higher noncontrolling interests and redeemable noncontrolling interests. Also, the Company’s payment of preference share dividends increased period-over-period due to preference shares issued in 2014 to fund the Company’s growth capital program. Finally, the ACFFO for each period was also adjusted for the cash effect of certain unusual, non-recurring or non-operating factors as discussed in Non-GAAP Reconciliations. ACFFO was $2,506 million for the year ended December 31, 2014 compared with $2,527 million for the year ended December 31, 2013. As discussed in Adjusted Earnings above, the Company experienced a year-over-year growth in its adjusted earnings which also positively impacted its ACFFO. However, this positive effect from adjusted earnings growth was more than offset by higher distributions in 2014 to noncontrolling interests and redeemable noncontrolling interests, higher preference share dividends resulting from preference shares issued over the last two years and higher maintenance capital expenditures in 2014. Impact of the Recent Decline in Commodity Prices Enbridge’s value proposition is built on the foundation of its reliable business model. The majority of its earnings and cash flow are generated from tolls and fees charged for the energy delivery services that it provides to its customers. Business arrangements are structured to minimize exposure to commodity price movements and any residual exposure is closely monitored and managed through disciplined hedging programs. Commercial structures are typically designed to provide a measure of protection against the risk of a scenario where falling commodity prices indirectly impact the utilization of the Company’s facilities. Protection against volume risk is generally achieved through regulated cost of service tolling arrangements, long-term take-or-pay contract structures and fee for service arrangements with specific features to mitigate exposure to falling throughput. Smaller components of Enbridge’s earnings are more exposed to the impacts of commodity price volatility. This includes Energy Services, where opportunities to benefit from location, time and quality differentials can be affected by commodity market conditions. They also include the Company’s interest in Aux Sable’s natural gas extraction and fractionation facilities and EEP’s natural gas gathering and processing businesses; however, the impact on Enbridge’s overall financial performance is relatively small and any inherent commodity price risk is mitigated by hedging programs, commercial arrangements and Enbridge’s partial ownership interest. In the third quarter of 2014, the price of crude oil began a dramatic decline. Benchmark prices for crude, which had been trading over US$105 per barrel in June 2014, fell to as low as US$37 per barrel by the end of 2015 as a result of significant increases in production both inside and outside of North America. Prices have declined further since the beginning of 2016, falling to below US$30 per barrel in January and are expected to remain volatile in the near to mid-term as the market seeks to re-balance supply and demand. The current commodity price environment has had an impact on shippers on Enbridge’s pipelines who have responded to price declines by reducing investment in exploration and development programs throughout 2015 and into 2016. Although Enbridge is exposed to throughput risk under the Competitive Toll Settlement (CTS) on the Canadian Mainline and under certain tolling agreements applicable to other liquids pipelines assets, the reduction in investment by the Company’s shippers is not expected to materially impact the financial performance of the Company. It is expected that existing conventional and oil sands production should be more than sufficient to support continued high utilization of the Canadian mainline. Entering 2016, nominations for service on the pipelines have continued to exceed available capacity on the system, resulting in apportionment of nominated volumes. Due to the nature of the commercial structures described above, Enbridge’s earnings and cash flow are not expected to be materially affected by the current low price environment. The decline in oil prices is also causing some sponsors of oil sands development programs to reconsider the timing of previously announced upstream development projects. Cancellation or deferral of these projects would affect longer-term supply growth from the Western Canadian Sedimentary Basin (WCSB). Enbridge’s existing growth capital program described under Growth Projects –Commercially Secured Projects has been commercially secured and is expected to generate reliable and predictable earnings growth through 2019 and beyond. Importantly, after taking into account the potential for some of these projects to be cancelled or deferred in an environment where low prices persist, Enbridge’s most recent near-term supply forecast reaffirms that the expansions and extensions of its liquids pipeline system completed in 2015 and currently in progress will provide cost-effective transportation services to key markets in North America and will be well utilized. 24 Enbridge Inc. 2015 Annual Report
Similar to the crude oil price trend, prices for NGL have decreased sharply as they are, to varying extents, correlated to crude oil. As well, in some cases NGL components have also been experiencing regional supply imbalances that have exacerbated an already challenging environment. Natural gas prices had already been relatively low for some time as production growth continued to outpace demand growth, but the pace of the price decline hastened in 2015 with continuing production levels resulting in rising inventories in storage which reached an all-time record high in November 2015. In the current low-price environment, Enbridge is working closely with producers to find ways to optimize capacity and provide enhanced access to markets in order to alleviate locational pricing discounts. Examples include the recently completed expansion of the Company’s liquids mainline system which resulted in the partial alleviation of upstream apportionment experienced in the first half of 2015 and completion of the Company’s reversal and capacity expansion of Line 9B as well as the completion of the Southern Access Extension Project (Southern Access Extension) in the fourth quarter of 2015, which have provided access to the Eastern Canada and Patoka markets, respectively. Cash Flows Cash provided by operating activities was $4,571 million for the year ended December 31, 2015, mainly driven by strong operating performance from the Company’s core assets, particularly from Liquids Pipelines and Sponsored Investments, and the cash flow generated from growth projects placed into service in recent years. Partially offsetting these cash inflows were changes in operating assets and liabilities as further discussed in Liquidity and Capital Resources. In the first eight months of 2015, during the design and negotiation of the Canadian Restructuring Plan, the Company did not access the public capital markets as regularly as it had in previous years. However, following the closing of the Canadian Restructuring Plan, Enbridge again began to access the public debt and equity markets in normal course. In 2015, Enbridge through its sponsored vehicles issued equity of approximately $1.1 billion. In addition, Enbridge and its subsidiaries issued approximately $1.6 billion in medium-term notes, US$1.6 billion in senior notes and expanded and extended the average maturity of its secured credit facilities. The proceeds of the capital market transactions, together with additional borrowings from its credit facilities, cash generated from operations and cash on hand were more than sufficient to finance the Company’s approximately $8 billion of projects that were placed into service in 2015 and are expected to provide financing flexibility for the Company’s growth capital program in 2016. As discussed in Liquidity and Capital Resources, the Company also continues to utilize its sponsored vehicles to enhance its enterprise-wide funding program. Dividends The Company has paid common share dividends in every year since it became a publicly traded company in 1953. In December 2015, the Company announced a 14% increase in its quarterly dividend to $0.530 per common share, or $2.120 annualized, effective March 1, 2016. As described under the Canadian Restructuring Plan, Enbridge’s target dividend payout policy range is 40% to 50% of ACFFO. In 2015, the dividend payout was 50.0% (2014 – 46.4%; 2013 – 40.1%) of ACFFO. For the 10-year period ended December 2015, the Company’s compound annual average dividend growth rate was 13.9%. Revenues The Company generates revenues from three primary sources: commodity sales, gas distribution sales and transportation and other services. Commodity sales of $23,842 million for the year ended December 31, 2015 (2014 – $28,281 million; 2013 – $26,039 million) were generated primarily through the Company’s energy services operations. Energy Services includes the contemporaneous purchase and sale of crude oil, natural gas and NGL to generate a margin, which is typically a small fraction of gross revenue. While sales revenues generated from these operations are impacted by commodity prices, net margins and earnings are relatively insensitive to commodity prices and reflect activity levels which are driven by differences in commodity prices between locations and points in time, rather than on absolute prices. Any residual commodity margin risk is closely 06 0.58 07 0.62 Dividends 08 0.66 per 09 0.74 10 0.85 Common 11 0.98 12 1.13 Share 13 1.26 14 1.40 15 1.86 16e 2.12 Management’s Discussion & Analysis 25
monitored and managed. Revenues from these operations depend on activity levels, which vary from year to year depending on market conditions and commodity prices. Gas distribution sales revenues are primarily earned by EGD and are recognized in a manner consistent with the underlying rate-setting mechanism mandated by the regulator. Revenues generated by the gas distribution businesses are driven by volumes delivered, which vary with weather and customer composition and utilization, as well as regulator-approved rates. The cost of natural gas is passed through to customers through rates and does not ultimately impact earnings due to its flow-through nature. Transportation and other services revenues are earned from the Company’s crude oil and natural gas pipeline transportation businesses and also include power production revenues from the Company’s portfolio of renewable and power generation assets. For the Company’s transportation assets operating under market-based arrangements, revenues are driven by volumes transported and tolls. For assets operating under take-or-pay contracts, revenues reflect the terms of the underlying contract for services or capacity. For rate-regulated assets, revenues are charged in accordance with tolls established by the regulator, and in most cost-of-service based arrangements are reflective of the Company’s cost to provide the service plus a regulator-approved rate of return. Higher transportation and other services revenues reflected increased throughput on the Company’s core liquids pipeline assets combined with the incremental revenues associated with assets placed into service over the past two years. The Company’s revenues also included changes in unrealized derivative fair value gains and losses related to foreign exchange and commodity price contracts used to manage exposures from movements in foreign exchange rates and commodity prices. The unrealized mark-to-market accounting creates volatility and impacts the comparability of revenues in the short-term, but the Company believes over the long term, the economic hedging program supports reliable cash flows and dividend growth. Forward-Looking Information Forward-looking information, or forward-looking statements, have been included in this MD&A to provide information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected ACFFO; expected future cash flows; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the Canadian Restructuring Plan (or the Transaction); dividend payout policy and dividend payout expectation. Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, NGL and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; expected exchange rates; inflation; interest rates; availability and price of labour and pipeline construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; weather; the impact of the Transaction and dividend policy on the Company’s future cash flows; credit ratings; capital project funding; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows and expected future ACFFO; and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates and may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings/(loss), adjusted earnings/(loss) and associated per share amounts, ACFFO, the impact of the Transaction on Enbridge or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer and regulatory approvals on construction and in-service schedules. Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Transaction, dividend policy, operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, public opinion, changes in tax law and tax rate increases, exchange rates, interest rates, commodity prices and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking 26 Enbridge Inc. 2015 Annual Report
statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements. Non-GAAP Measures This MD&A contains references to adjusted earnings/(loss) and ACFFO. Adjusted earnings/(loss) 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 and losses are presented net of amounts realized on the settlement of derivative contracts during the applicable period. ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in regulatory assets and liabilities and environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. Management believes the presentation of adjusted earnings/(loss) and ACFFO provide useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company. Management uses adjusted earnings/(loss) to set targets and to assess the performance of the Company. Management also uses ACFFO to assess the performance of the Company and to set its dividend payout target. Adjusted earnings/(loss), adjusted earnings/(loss) for each segment and ACFFO are not measures that have standardized meaning prescribed by U.S. GAAP and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. The tables below summarize the reconciliation of the GAAP and non-GAAP measures. Non-GAAP Reconciliations Earnings/(Loss) to Adjusted Earnings Three months ended Year ended December 31, December 31, 2015 2014 2015 2014 2013 (millions of Canadian dollars) Earnings/(loss) attributable to common shareholders 378 88 (37) 1,154 446 1 Adjusting items 2 Changes in unrealized derivative fair value loss 45 164 1,380 320 843 Canadian Restructuring Plan – – 351 –– Goodwill impairment loss – – 167 –– Make-up rights adjustments 30 11 30 17 50 Leak remediation costs, net of leak insurance recoveries (13) (9) (17) 894 Warmer/(colder) than normal weather 16 (1) (11) (36) (9) Gains on sale of non-core assets and investment, net of losses – (14) (46) (71) (2) Asset impairment losses 13 2 13 26 Employee severance costs 25 1 25 1– Valuation allowance on deferred income tax assets – – 32 –– Project development and transaction costs – 8 14 14 – Tax on intercompany gains on sale of partnership units – 157 39 157 – Out-of-period adjustments – – (71) –25 Other – 2 (3) 8(19) Adjusted earnings 494 409 1,866 1,574 1,434 1 The above table summarizes adjusting items by nature. For a detailed listing of adjusting items by segment, refer to individual segment discussions. 2 Changes in unrealized derivative fair value gains and loss are presented net of amounts realized on the settlement of derivative contracts during the applicable period. Management’s Discussion & Analysis 27
Available Cash Flow from Operations Three months ended Year ended December 31, December 31, 2015 2014 2015 2014 2013 (millions of Canadian dollars) Cash provided by operating activities–continuing operations 806 656 4,571 2,528 3,333 1 Adjusted for changes in operating assets and liabilities 474 470 688 1,777 272 1,280 1,126 5,259 4,305 3,605 Distributions to noncontrolling interests (179) (140) (680) (535) (468) Distributions to redeemable noncontrolling interests (34) (24) (114) (79) (72) Preference share dividends (74) (71) (288) (245) (178) 2 Maintenance capital expenditures (200) (312) (720) (970) (752) Significant adjusting items: Weather normalization 16 (1) (11) (36) (9) Project development and transaction costs 2 15 44 19 – 3 Realized inventory revaluation allowance (52) – (474) –– Hydrostatic testing 23 – 72 –– Leak remediation costs, net of leak insurance recoveries – – – –345 Employee severance costs 30 6 30 6– Other items 64 11 36 41 56 Available cash flow from operations(ACFFO) 876 610 3,154 2,506 2,527 1 Changes in operating assets and liabilities include changes in regulatory assets and liabilities and environmental liabilities, net of recoveries. 2 Maintenance capital expenditures are expenditures that are required for the ongoing support and maintenance of the existing pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete, or completing their useful lives). For the purpose of ACFFO, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets. 3 Realized inventory revaluation allowance relates to losses on sale of previously written down inventory for which there is an approximate offsetting realized derivative gain in ACFFO. Corporate Vision and Strategy Vision Enbridge’s vision is to be the leading energy delivery company in North America. In pursuing this vision, the Company plays a critical role in enabling the economic well-being and quality of life of North Americans, who depend on access to plentiful energy. The Company transports, distributes and generates energy, and its primary purpose is to deliver the energy North Americans need in the safest, most reliable and most efficient way possible. Among its peers, Enbridge strives to be the leader, which means not only leadership in value creation for shareholders but also leadership with respect to worker and public safety and environmental protection associated with its energy delivery infrastructure, as well as in customer service, community investment and employee satisfaction. Driven by this vision, the Company delivers value for shareholders from a proven and unique value proposition, which combines visible growth, a reliable business model and a dependable and growing income stream. Strategy The Company’s initiatives centre around eight areas of strategic emphasis in four key focus areas. These strategies are reviewed at least annually with direction from the Company’s Board of Directors. Commitment to Safety and Operational Reliability Execute Secure the Longer-Term Future Focus on project management Strengthen core businesses Preserve financing strength and flexibility Develop new platforms for growth and diversification Maintain the Foundation Uphold Enbridge values Maintain the Company’s social license to operate Attract, retain and develop highly capable people 28 Enbridge Inc. 2015 Annual Report
Commitment to Safety and Operational Reliability Safety and operational reliability remains the Company’s number one priority and sets the foundation for the strategic plan. The commitment to safety and operational reliability means achieving and maintaining industry leadership in safety (process, public and personal) and ensuring the reliability and integrity of the systems the Company operates in order to generate, transport and deliver the energy society counts on and to protect the environment. Under the umbrella of the Company’s Operational Risk Management Plan (ORM Plan) introduced in 2010, Enbridge has undertaken extensive maintenance, integrity and inspection programs across its pipeline systems. The ORM Plan has resulted in strong improvements in the area of safety and operational risk management, bolstering incident response capabilities, employee and public safety protocols and improved communications with landowners and first responders. In addition, an enterprise-wide safety and risk management framework has been implemented to ensure the Company identifies, prioritizes and effectively prevents and mitigates risks across the enterprise. The Company strives to embed a common risk management framework within its operations and those of its joint venture partners. Supporting these initiatives is a safety culture that strives towards a target of 100% safe operations, with a belief that all incidents can be prevented. To achieve the goal of industry leadership, the Company measures its performance as compared to standard industry performance, transparently reports its results and continues to use external assessments to measure its performance. Execute Focus on Project Management Enbridge’s objective is to safely deliver projects on time and on budget and at the lowest practical cost while maintaining the highest standards for safety, quality, customer satisfaction and environmental and regulatory compliance. With an approximate $26 billion portfolio of commercially secured growth projects, successful project execution is critical to achieving the Company’s long-term growth plan. These projects are predominantly liquids focused, but increasingly include green energy, natural gas, offshore and gas distribution initiatives. Enbridge, through its Major Projects Group (Major Projects), continues to build upon and enhance the key elements of its rigorous project management processes including: employee and contractor safety; long-term supply chain agreements; quality design, materials and construction; extensive regulatory and public consultation; robust cost, schedule and risk controls; and efficient project transition to operating units. Preserve Financing Strength and Flexibility The maintenance of adequate financing strength and flexibility is crucial to Enbridge’s growth strategy. Enbridge’s financing strategies are designed to ensure the Company has sufficient financial flexibility to meet its capital requirements. To support this objective, the Company develops financing plans and strategies to manage credit ratings, diversify its funding sources and maintain substantial standby bank credit capacity and access to capital markets in both Canada and the United States. As part of the Company’s risk management policy, the Company engages in a comprehensive long-term economic hedging program to mitigate the impact of fluctuations in interest rates, foreign exchange and commodity price on the Company’s earnings. This economic hedging program together with ongoing management of credit exposures to customers, suppliers and counterparties supports one of the key tenets of the Company’s investor value proposition, a reliable business model. Enbridge has also actively used its sponsored vehicles, primarily through asset drop downs, to cost-effectively fund a portion of its large growth capital program. In 2015, the Company completed the Canadian Restructuring Plan, which transferred the majority of its Canadian Liquids Pipelines business and certain renewable energy assets to the Fund Group. See Canadian Restructuring Plan. For further discussion on the Company’s financing strategies, refer to Liquidity and Capital Resources. The Company continually assesses ways to generate value for shareholders, including reviewing opportunities that may lead to acquisitions, dispositions or other strategic transactions, some of which may be material. Opportunities are screened, analysed and assessed using strict operating, strategic and financial criteria with the objective of ensuring the effective deployment of capital and the enduring financial strength and stability of the Company. Secure the Longer-Term Future Strengthen Core Businesses Within the Company’s crude oil transportation business, strategies to strengthen the core business are focused on optimizing asset performance, strengthening stakeholder and customer relationships and providing access to new markets for production from western Canada and the Bakken regions, all while ensuring safe and reliable operations. The Company’s asset optimization efforts focus on maximizing the operational and financial performance of its infrastructure assets within established risk parameters, providing competitive services and value to customers. The Company’s assets are strategically located and well-positioned to capitalize on opportunities. Over the past year, Enbridge continued to execute on its Gulf Coast Access Program through the completion of a phase of the Mainline Expansion project that increased the capacity of the liquids mainline system by 230,000 barrels per day (bpd) and contributed to record throughput levels on the liquids mainline in December 2015. Significant milestones were also reached on the Company’s Eastern Access Program, as the Company completed the reversal of Line 9B and placed the 300,000 bpd line into service in December 2015. The Eastern Access Program provides increased access to refineries in the upper midwest United States and eastern Canada. Under the Company’s Light Oil Market Access Program, Enbridge completed the Line 9 capacity expansion portion of the Line 9B project noted above as well as Southern Access Extension, which was completed in December 2015 and provides additional crude oil capacity of 300,000 bpd from Flanagan, Illinois to Patoka, Illinois. Additionally, EEP further expanded the capacity of the Lakehead System between Superior, Wisconsin and Griffith, Indiana through the completion of a phase of the Southern Access expansion in May 2015 and the completion of the twinning of the Spearhead North pipeline (Spearhead North Twin) in November 2015. While executing its record growth capital program in the recent years, the Company has also been undertaking an extensive integrity program across its liquids and gas systems. The Company’s Line 3 Replacement Program (L3R Program) will support the safety and operational reliability of the overall system and enhance the flexibility Management’s Discussion & Analysis 29
on the mainline system allowing the Company to further optimize throughput. For further details on the L3R Program, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments. The strategic focus within Regional Oil Sands Systems is to optimize existing asset corridors and provide innovative, creative, competitive and customer oriented solutions to WCSB producers to secure the incremental supply of crude oil expected from the western Canadian oil sands projects over the next decade. Within this regional focus area, Enbridge has approximately $5 billion of regional infrastructure growth projects currently under development which are expected to enter service from 2015 to 2017. Approximately $1 billion worth of projects were completed in 2015. Approximately $4 billion are expected to be completed and placed into service in 2016 and 2017. In the Bakken region, Enbridge and EEP’s growth is focused on the development and construction of the US$2.6 billion Sandpiper Project (Sandpiper). Upon completion, now expected for early 2019, Sandpiper will provide North Dakota producers enhanced access to premium light crude oil markets. For recent developments on this matter, refer to Growth Projects –Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Sandpiper Project. In addition to executing its secured growth program, the Company is focused on extending growth beyond 2019 through continued expansion of liquids pipelines, as well as development of its natural gas and power businesses. The Company’s natural gas strategies include leveraging the competitive advantages of its existing assets, expanding its footprint into emerging supply areas and establishing more direct linkage to growing markets. Combined, Alliance Pipeline and the Aux Sable NGL extraction and fractionation plant are well-positioned to provide liquids-rich gas transportation and processing to developing regions in northeast British Columbia, western Alberta and the Bakken. Alliance Pipeline has successfully re-contracted its firm capacity with shippers for an average contract length of approximately five years under its new services framework that commenced in December 2015. For further details, refer to Sponsored Investments – The Fund Group – Alliance Pipeline Recontracting. The Company continues to focus on expanding its Canadian Midstream footprint, primarily within the Montney and Duvernay formations, two of the most competitive natural gas and NGL plays in North America. Even during the depressed energy price environment in late 2015 and early 2016, the Montney play continues to attract active rigs. In January 2016, the Company reached agreement to purchase two operating natural gas plants (Tupper Main and Tupper West gas plants) and associated pipelines in northeastern British Columbia. Subject to regulatory review and approval, the transaction is expected to close in the second quarter of 2016. The Company also continues to pursue ultra-deep water offshore natural gas and crude oil transmission opportunities. In 2015, the Big Foot Gas Pipeline portion of the Walker Ridge Gas Gathering System (WRGGS), and the Big Foot Oil Pipeline (Big Foot Pipeline) projects were installed on the sea floor and are awaiting installation of the upstream facilities by producers. Further growth in earnings and cash flow from the Offshore business will come from the Heidelberg Oil Pipeline (Heidelberg Pipeline) which was placed into service in January 2016 and the Stampede Oil Pipeline (Stampede Pipeline) which is expected to be operational by 2018. Enbridge’s natural gas distribution business in eastern Canada is the largest in Canada with over two million customers. EGD is currently focused on the execution of the Greater Toronto Area (GTA) project, which is a key component of EGD’s gas supply strategy and will provide new transmission services that will enable access to mid-continent gas supplies for the utility and its customers. In 2014, the Ontario Energy Board (OEB) approved the second generation customized IR Plan which established natural gas distribution rates over a five-year period from 2014 to 2018. A key tenet of the customized IR Plan is that it allows EGD to recover costs for significant capital investment, including the GTA project. The customized IR Plan also allows EGD an opportunity to earn above an allowed return on equity (ROE), with any return over the allowed ROE for a given year to be shared equally with customers. The customized IR Plan serves to reinforce stability of the earnings and cash flow EGD delivers to Enbridge. Develop New Platforms for Growth and Diversification The development of new platforms to diversify and sustain long-term growth is an important strategic priority. The Company is currently focusing its development and diversification efforts towards securing investment in additional renewable energy generation, liquefied natural gas (LNG) development, gas-fired power generation and energy marketing, as well as exploring opportunities to extend its energy delivery and generation services to select energy markets outside North America. The Company also invests in early stage energy technologies that complement the Company’s core businesses. In 2015, Enbridge continued to expand its interests in renewable power generation with the acquisitions of the 103-MW New Creek Wind Project (New Creek) in West Virginia and a 24.9% interest in the 400-MW Rampion Offshore Wind Project (Rampion Project) in the United Kingdom. Including these acquisitions, Enbridge has invested approximately $5 billion in renewable power generation and transmission since 2002. The Company’s goal is to take over full operational responsibility of its renewable power generation facilities as operating contracts with key service providers expire and if the associated economics are viable. The Company’s energy marketing business also plans to expand its business through obtaining capacity on energy delivery and storage assets in strategic locations to achieve higher earnings from location, grade and time differentials. Maintain the Foundation Uphold Enbridge Values Enbridge adheres to a strong set of core values that govern how it conducts its business and pursues strategic priorities, as articulated in its value statement: “Enbridge employees demonstrate integrity, safety and respect in support of our communities, the environment and each other”. Employees are expected to uphold these values in their interactions with each other, customers, suppliers, landowners, community members and all others with whom the Company deals and ensure the Company’s business decisions are consistent with these values. Employees and contractors are required, on an annual basis, to certify their compliance with the Company’s Statement on Business Conduct. 30 Enbridge Inc. 2015 Annual Report
Maintain the Company’s Social License to Operate Earning and maintaining “social license”—the acceptance by the communities in which the Company operates or is proposing new projects—is critical to Enbridge’s ability to execute on its growth plans. To earn public acceptance of Enbridge and its projects, the Company is increasingly focused on building long-term relationships by understanding, accommodating and resolving public concerns related to the Company’s projects and operations. The Company engages its key stakeholders through collaboration and by demonstrating openness and transparency in its communication. The Company also focuses on enhancing the Government Relations function with a goal of advocating company positions on key issues and policies that are critical to its business. The Company also builds awareness of the role energy and Enbridge play in people’s lives in order to promote better understanding of the Company and its businesses. To earn the public’s trust, and to help protect and reinforce the Company’s reputation with its stakeholders, Enbridge is committed to integrating Corporate Social Responsibility (CSR) into every aspect of its business. The Company defines CSR as conducting business in an ethical and responsible manner, protecting the environment and the safety of people, providing economic and other benefits to the communities in which the Company operates, supporting universal human rights and employing a variety of policies, programs and practices to manage corporate governance and ensure fair, full and timely disclosure. The Company provides its stakeholders with open, transparent disclosure of its CSR performance and prepares its annual CSR Report using the Global Reporting Initiative G4 sustainability reporting guidelines, which serve as a generally accepted framework for reporting on an organization’s economic, environmental and social performance. The Company also executes a number of specific projects, programs and initiatives to ensure the perspective of its stakeholders help guide business decision making on sustainable development issues. For example, through its Neutral Footprint Program, originally adopted in 2009, the Company committed to help reduce the environmental impact of its liquid pipeline expansion projects within five years of their occurrence by meeting goals for replacing trees, conserving land and generating kilowatt hours of green energy. During the last five years the Neutral Footprint Program has met these targets and continued to do so in 2015. The Company has consulted with stakeholders on the development of a next generation of environmental commitments that reflect the shifting energy landscape in North America, including changing business needs, regulatory conditions and public expectations. In 2016 the Company plans to update its environmental goals to address growing public interest in its role on climate and energy issues, as well as new activities and relationships on water protection. The Company’s CSR Report can be found at csr.enbridge.com and progress updates on the Company’s Neutral Footprint initiatives can be found in the annual CSR Report. Unless otherwise specifically stated, none of the information contained on, or connected to, the Enbridge website is incorporated by reference in, or otherwise part of this MD&A. To complement community investments in its Canadian and United States operating areas, Enbridge created the energy4everyone Foundation (the Foundation) in 2009. The Foundation aims to leverage the expertise and resources of the Canadian energy industry to effect significant positive change through the delivery and deployment of affordable, reliable and sustainable energy services and technologies in communities in need around the world. To date, the Foundation has completed projects in Costa Rica, Ghana, Nicaragua, Peru and Tanzania. Attract, Retain and Develop Highly Capable People Investing in the attraction, retention and development of employees and future leaders is fundamental to executing Enbridge’s growth strategy and creating sustainability for future success. Recently, in view of the commodity price downturn in the energy industry, the Company reduced its workforce by approximately 5% in order to maintain its competitiveness in the industry so it can continue to serve its stakeholders well and further strengthen its foundation for the future. The Company focuses on enhancing the capability of its people to maximize the potential of the organization and undertakes various activities such as offering accelerated leadership development programs, enhancing career opportunities and building change management capabilities throughout the enterprise so that projects and initiatives achieve intended benefits. Furthermore, Enbridge strives to maintain industry competitive compensation and retention programs that provide both short-term and long-term incentives. Industry Fundamentals Supply and Demand for Liquids Enbridge has an established and successful history of being the largest transporter of crude oil to the United States, the world’s largest market. While United States’ demand for Canadian crude oil production will support the use of Enbridge infrastructure for the foreseeable future, North American and global crude oil supply and demand fundamentals are shifting, and Enbridge has a role to play in this transition by developing long-term transportation options that enable the efficient flow of crude oil from supply regions to end-user markets. As discussed in Performance Overview – Impact of the Recent Decline in Commodity Prices, crude oil prices fell by close to 50% in the latter half of 2014 and continued to fall to US$37 by the end of 2015, with a further decline to below US$30 in January 2016. The international market for crude oil has seen a significant increase in production from North American basins and increased production from the Organization of Petroleum Exporting Countries (OPEC) in the face of slower global demand growth. The downturn in price has impacted Enbridge’s liquids pipelines’ customers, who have responded by reducing their exploration and development spending for 2015 and into 2016. Notwithstanding the recent price decline, the Enbridge system has thus far continued to be highly utilized. The mainline system continues to be subject to apportionment of heavy crudes, as nominated volumes currently exceed capacity on portions of the system. Impact of the decline in crude oil prices to the financial Management’s Discussion & Analysis 31
performance of Enbridge’s liquids pipelines business is expected to be relatively modest given the commercial arrangements which underpin many of the pipelines that make up the liquids system and provide a significant measure of protection against volume fluctuations. In addition, the Enbridge mainline is well positioned to continue to provide safe and efficient transportation which will enable western Canadian and Bakken production to reach attractive markets in the United States at a competitive cost relative to other alternatives. The fundamentals of oil sands production and the recent decline in crude oil prices has caused some sponsors to reconsider the timing of their upstream oil sands development projects; however, recently updated forecasts continue to reflect long-term supply growth from the WCSB, although the projected pace of growth is slower than previous forecasts as companies continue to assess the viability of certain capital investments in the current low price environment. Over the long term, global energy consumption is expected to continue to grow, with the growth in crude oil demand primarily driven by emerging economies in regions outside the Organization for Economic Cooperation and Development (OECD), mainly China and India. While OECD countries, including Canada, the United States and western European nations, will experience population growth, emphasis placed on energy efficiency, conservation and a shift to lower carbon fuels, such as natural gas and renewables, will reduce crude oil demand over the long term. Accordingly, there is a strategic opportunity for North American producers to grow production to displace foreign imports and participate in the growing global demand outside North America. In terms of supply, long-term global crude oil production is expected to continue to grow through 2035, with growth in supply primarily contributed by North America and OPEC. Growth in North America is largely driven by production from the oil sands, the Gulf of Mexico and the continued development of tight oil plays including the Bakken, Eagle Ford and Permian formations. Growth in supply from OPEC is primarily a result of a shift in OPEC’s strategy from ‘balancing supply’ to ‘competing for market share’ in Asia and Europe. However, political uncertainty in certain oil producing countries, including Libya and Iraq, increases risk in those regions’ supply growth forecasts and makes North America one of the most secure supply sources of crude oil. As witnessed throughout 2015 and early 2016, North American supply growth can be influenced by macro-economic factors that drive down the global crude prices. Over the longer term, North American production from tight oil plays, including the Bakken, is expected to grow as technology continues to improve well productivity and reduce costs. The WCSB, in Canada, is viewed as one of the world’s largest and most secure supply sources of crude oil. However, the pace of growth in North America and level of investment in the WCSB could be tempered in future years by a number of factors including a sustained period of low crude oil prices and corresponding production decisions by OPEC, increasing environmental regulation, prolonged approval processes for new pipelines and the continuation of access restrictions to tide-water in Canada for export. The combination of relatively flat domestic demand, growing supply and long-lead time to build pipeline infrastructure has led to a fundamental change in the North American crude oil landscape. In recent years, an inability to move increasing inland supply to tide-water markets resulted in a divergence between West Texas Intermediate (WTI) and world pricing, resulting in lower netbacks for North American producers than could otherwise be achieved if selling into global markets. The impact of price differentials has been even more pronounced for western Canadian producers as insufficient pipeline infrastructure resulted in a further discounting of Alberta crude against WTI. With a number of market access initiatives recently completed by the industry, including those introduced by Enbridge, the crude oil price differentials significantly narrowed in 2015, and resulted in higher netbacks for producers. This has resulted in crude oil moving off of alternative transportation such as rail to fill the additional pipeline capacity as it became available. However, Canadian pipeline export capacity remains essentially full, and production growth once again is increasing its use of non-pipeline transportation services. As the supply in North America continues to grow, the growth and flexibility of pipeline infrastructure will need to keep pace with the sensitive demand and supply balance. Over the longer term, the Company believes pipelines will continue to be the most cost-effective means of transportation in markets where the differential between North American and global oil prices remain narrow. Utilization of rail to transport crude is expected to be substantially limited to those markets not readily accessible by pipelines. Canadian Crude Oil Production (thousands of barrels per day) 3,757 3,695 3,783 3,477 13 14 15 16e ? Oil Sands ? Other Sources: National Energy Board, Canadian Association of Petroleum Producers 32 Enbridge Inc. 2015 Annual Report
Enbridge’s role in helping to address the evolving supply and demand fundamentals and alleviating price discounts for producers and supply costs to refiners is to provide expanded pipeline capacity and sustainable connectivity to alternative markets. As discussed in Growth Projects – Commercially Secured Projects, in 2015, Enbridge continued to execute its growth projects plan in furtherance of this objective. As prices continue to remain sensitive to capacity limitations to markets, there is a heightened need to expand access to coastal markets. Details of the Company’s Northern Gateway Project (Northern Gateway), a proposed pipeline system from Alberta to the coast of British Columbia, and associated marine terminal, along with the Company’s other projects under development, can be found in Other Announced Projects Under Development. Supply and Demand for Natural Gas and NGL Despite the recent slowing of China’s economic growth, global energy demand is expected to increase over time, driven by expected economic growth from non-OECD countries. Natural gas will play an important role in meeting this energy demand and is anticipated to be one of the world’s fastest growing energy sources. Most natural gas demand will stem from the need for greater power generation capacity, as natural gas is a cleaner alternative to coal, which has the largest market share for power generation. Within North America, United States natural gas demand is also expected to be driven by the next wave of gas-intensive petrochemical facilities which are expected to enter service over the next two years along with the commissioning of the first of several LNG export facilities in 2016. Over the longer term, higher United States natural gas demand is expected to be driven by the industrial sector and from power generation and will be supplemented by higher exports, via LNG and to Mexico. Within Canada, natural gas demand growth is expected to be largely tied to oil sands development and growth in gas-fired power generation. Similar to crude oil, robust North American supply from tight formations has created a demand and supply imbalance for natural gas and some NGL products. North American gas supply continues to be significantly impacted by development in the northeastern United States, primarily the prolific Marcellus shale, as well as the rapidly growing Utica shale. The abundance of supply from these shale plays has fundamentally altered natural gas flow patterns in North America. For example, flows from the United States Gulf Coast and WCSB that historically supplied eastern markets, have largely been displaced. Similar pressures are also being felt in the Midwest and southern markets. As a result, natural gas production from regions other than the northeastern United States has largely been flat or has declined over the past several years in the face of lower-cost production from the Appalachian region in addition to prolonged weak North American natural gas prices. While low natural gas prices are expected to be a key driver in future natural gas demand and infrastructure growth, it is also expected that gas supply will remain ample and could respond quickly to rising demand thereby limiting price advances. With the weak natural gas price environment over the last several years, producers had broadly shifted from dry gas drilling to developing rich gas reservoirs to take advantage of the relatively higher value of NGL inherent in the gas stream. NGL that can be extracted from liquids-rich gas streams include ethane, propane, butane and natural gasoline, which are used in a variety of industrial, commercial and other applications. However, the combined effects of much lower crude prices and regional supply imbalances for some NGL products have weakened the economics of NGL extraction to the extent that some producers have returned to drilling prolific dry gas plays which exhibit lower supply costs. Nonetheless, over the longer term, the growth in NGL demand is expected to be robust, driven largely by incremental ethane demand. Ethane is the key feedstock to the United States Gulf Coast petrochemical industry which is the world’s second lowest-cost ethylene production region and is currently undergoing significant expansion. However, until this new infrastructure is completed and online, ethane prices and resulting extraction margins are expected to continue to remain low due to the current oversupply, with high volumes of ethane being retained in the gas stream rather than extracted. Similarly, rapidly growing supplies of propane have been outpacing demand leading to record storage levels and North American Natural Gas Production (billions of cubic feet per day) 1 2 . . . 8 89 89 . 3 84 80 13 14 15 16e ? Shale ? Other Sources: Energy Information Administration (United States), National Energy Board (Canada), Enbridge Gas Fundamentals Management’s Discussion & Analysis 33
downward pressure on prices. The outlook for abundant propane supplies in excess of domestic demand has prompted the development and expansion of export facilities for liquefied petroleum gas (LPG). Over a few short years, the United States has become the world’s largest LPG exporter. In Canada, the WCSB basin is well-situated to capitalize on the evolving NGL fundamentals over the longer term as the Montney formation in northern British Columbia and the Duvernay shale in Alberta contain significant liquids-rich resources at competitive extraction costs. While longer-term NGL fundamentals provide a positive outlook for growth, a sustained period of low crude oil prices and the related negative impact on NGL prices could temper future growth. Weak prices for NGL, which generally trade at a percentage of crude oil prices, have also caused a reduction in investment for liquids-rich gas drilling programs and related extraction facilities, thereby limiting production growth. However, robust gas production from highly economic core areas within certain shale plays, particularly the Marcellus, is expected to continue to offset any price related production declines from other supply regions over the next year. To the extent oil prices recover, the crude-to-gas price ratio is expected to rise from current levels. The immense and readily available gas supply within North America will likely continue to limit price increases. Consequently, the crude-to-gas price ratio is expected to remain well above energy conversion value levels and continue to be supportive of NGL extraction over the longer term. Although United States based LNG export projects have successfully executed sales contracts with pricing indexed to North American gas prices, the price for LNG in global markets has typically been more closely linked to crude oil prices, providing western Canadian producers with an opportunity to capture more favourable netbacks on LNG exports upon a recovery in crude prices, if that pricing linkage is maintained. Based on the prospect for higher global LNG demand, the large resource base in western Canada and the changing North American natural gas flow patterns discussed above, there is an expectation that projects to export LNG from the west Coast of Canada will proceed in the next decade. However, a sustained period of low crude oil prices or other changes in global supply and demand for natural gas could delay such opportunities. In response to these evolving natural gas and NGL fundamentals, Enbridge believes it is well-positioned to provide value-added solutions to producers. Alliance Pipeline traverses through the heart of key liquids-rich plays in the WCSB and is uniquely positioned to transport liquids-rich gas. Alliance Pipeline has developed new service offerings to best meet the needs of producers and shippers, and demand for transportation services on the Alliance Pipeline continues to be robust. The focus on liquids-rich gas development also creates opportunities for Aux Sable, an extraction and fractionation facility near Chicago, Illinois near the terminus of Alliance Pipeline. Enbridge is also responding to the need for regional infrastructure with additional investment in Canadian and United States midstream processing and pipeline facilities. Supply and Demand for Renewable Energy The power generation and transmission network in North America is expected to undergo significant growth over the next 20 years. On the demand side, North American economic growth over the longer term is expected to drive growing electricity demand, although continued efficiency gains are expected to make the economy less energy-intensive and temper demand growth. On the supply side, impending legislation in both Canada and the United States is expected to accelerate the retirement of aging coal-fired generation plants, resulting in a requirement for significant new generation capacity. While coal and nuclear facilities will continue to be core components of power generation in North America, gas-fired and renewable energy facilities, including biomass, hydro, solar and wind, are expected to be the preferred sources to replace coal-fired generation due to their lower carbon intensities. North American wind and solar resources fundamentals remain strong. In the United States there is over 74 gigawatts (GW) of installed wind power capacity and in Canada over 11 GW of capacity. Solar resources in southwestern states such as Arizona, California and Nevada are considered to be some of the best in the world for large-scale solar plants and the United States currently has over 24 GW of installed solar photovoltaic capacity. In addition, in late 2015, the United States passed legislation extending the availability of certain Federal tax incentives which have supported the profitability of wind and solar projects. However, expanding renewable energy infrastructure in North America is not without challenges. Growing renewable generation capacity is expected to necessitate substantial capital investment to upgrade existing transmission systems or, in many cases, build new transmission lines, as these high quality wind and solar resources are often found in regions that are not in close proximity to markets. In the near-term, uncertainty over the availability of tax or other government incentives in various jurisdictions, the ability to secure long-term power purchase agreements (PPA) through government or investor-owned power authorities and low market prices of electricity may hinder the pace of future new renewable capacity development. However, continued improvement in technology and manufacturing capacity in the past few years has reduced capital costs associated with renewable energy infrastructure and has also improved yield factors of power generation assets. These positive developments are expected to render renewable energy more competitive and support ongoing investment over the long term. In Europe the future outlook for renewable energy, especially from offshore wind in countries with long coastlines and densely populated areas, is very positive. Over EUR250 billion of investment is forecast in the European offshore wind industry up to 2030. There is also wide public support for carbon reduction targets and broader adoption of renewable generation across all governmental levels. Furthermore, governments in Europe look to rationalize the contribution of nuclear power to the overall energy mix, which has resulted in an increased focus on alternative sources such as large scale offshore wind. 34 Enbridge Inc. 2015 Annual Report
Enbridge continues to expand its renewable asset footprint and is one of Canada’s largest wind and solar power generators. In late 2015, Enbridge announced acquisitions of the 103-MW New Creek in West Virginia and a 24.9% interest in the 400-MW Rampion Project in the United Kingdom. Including these acquisitions, Enbridge has invested approximately $5 billion in renewable power generation and transmission since 2002. The Company will continue to seek new opportunities to expand its power generation business, growing its portfolio by investing in assets that meet its investment criteria. Growth Projects— Commercially Secured Projects A key focus of Enbridge’s corporate strategy is the successful execution of its growth capital program. In 2015, Enbridge successfully placed into service approximately $8 billion of growth projects across several business units. Enbridge’s remaining portfolio of approximately $18 billion of growth projects is expected to be placed into service by 2019, with approximately $2 billion expected to come into service during 2016. Over the past few years, Enbridge’s growth capital program has been anchored by three major market access initiatives, supported by several mainline system expansion and regional infrastructure projects that are designed to ensure that there is sufficient capacity to support these new market access extensions. The three major market access initiatives are: the Gulf Coast Access Program; • the Eastern Access Program; and • the Light Oil Market Access Program. • The Gulf Coast Access Program included the Seaway Pipeline, Seaway Crude Pipeline System Twin (Seaway Pipeline Twin) and Flanagan South projects that were completed in 2014, as well as elements of the Canadian Mainline and Lakehead System Mainline expansions. These projects have increased access to refinery markets in the Gulf Coast. In 2015, Enbridge completed its Gulf Coast Access Program with the completion of a phase of the Mainline Expansion project that increased the capacity of the liquids mainline system by 230,000 bpd. The Company’s Eastern Access Program has allowed for greater access for crude oil into Chicago, further east into Toledo and ultimately into Ontario and Quebec. The Eastern Access Program included the Company’s Toledo pipeline expansion, Line 9 reversal, the Spearhead North pipeline expansion, Line 6B replacement and Line 5 expansion. With the reversal of Line 9B and placement of this 300,000 bpd line into service in December 2015, the Company completed the Eastern Access Program in 2015. Finally, the Light Oil Market Access Program brings together a group of projects to transport an increasing supply of light oil from Canada and the Bakken and supplement the Eastern Access Program through the upsizing of Line 9B and the Line 6B capacity expansion. The Light Oil Market Access Program also includes Southern Access Extension, Sandpiper, Canadian Mainline System Terminal Flexibility and Connectivity, Spearhead North Twin (Line 78) and Southern Access expansion included within the Lakehead System Mainline Expansion. The Company made significant progress on this program during 2015 completing the capacity expansion portion of the Line 9B project and the Southern Access Extension, both of which were placed into service in December 2015. Additionally, EEP further expanded the capacity of the Lakehead System between Superior, Wisconsin and Griffith, Indiana through the completion of phases of the Southern Access expansion in May 2015 and October 2015, as well as the completion of the Spearhead North Twin (Line 78) in November 2015. In keeping with the Company’s strategic priority to develop new platforms to diversify and sustain long-term growth, Enbridge continued to expand its renewable energy generation capacity in 2015. The Keechi Wind Project (Keechi) entered service in January 2015, increasing Enbridge’s net operating renewable power generating capacity to nearly 1,800-MW. Enbridge also announced acquisitions of the 103-MW New Creek in West Virginia and a 24.9% interest in the 400-MW Rampion Project in the United Kingdom, which are expected to be placed into service in 2016 and 2018, respectively, increasing Enbridge’s interests to nearly 2,000 MW of net renewable and alternative energy generating capacity. Management’s Discussion & Analysis 35
The following table summarizes the current status of the Company’s commercially secured projects, organized by business segment. Estimated Expenditures Expected 1 2 Capital Cost to Date In–Service Date Status (Canadian dollars, unless stated otherwise) Liquids Pipelines 1. Southern Access Extension US$0.6 billion US$0.6 billion 2015 Complete Gas Distribution 2. Greater Toronto Area Project $0.9 billion $0.8 billion 2016 Under construction (in phases) Gas Pipelines, Processing and Energy Services 3. Keechi Wind Project US$0.2 billion US$0.2 billion 2015 Complete 4. Walker Ridge Gas Gathering System US$0.4 billion US$0.3 billion 2014 – TBD Complete (in phases) 5. Big Foot Oil Pipeline US$0.2 billion US$0.2 billion TBD Complete 6. Heidelberg Oil Pipeline US$0.1 billion US$0.1 billion 2016 Complete 7. Tupper Main and Tupper West Gas Plants $0.5 billion No significant 2016 Acquisition in progress expenditures to date 8. Aux Sable Extraction Plant Expansion US$0.1 billion No significant 2016 Under construction expenditures to date 9. New Creek Wind Project US$0.2 billion No significant 2016 Pre-construction expenditures to date 10. Stampede Oil Pipeline US$0.2 billion No significant 2018 Pre-construction expenditures to date 11. Rampion Offshore Wind Project $0.8 billion $0.2 billion 2018 Under construction (Ł0.37 billion) (Ł0.10 billion) Sponsored Investments 12. The Fund Group – Eastern Access Line 9 $0.8billion $0.8billion 2013– 2015 Complete Reversal and Expansion (in phases) 13. The Fund Group – Canadian Mainline Expansion $0.7 billion $0.7 billion 2015 Complete 14. The Fund Group – Surmont Phase 2 Expansion $0.3billion $0.3billion 2014– 2015 Complete (in phases) 15. The Fund Group – Canadian Mainline System $0.7billion $0.7billion 2013– 2015 Complete Terminal Flexibility and Connectivity (in phases) 16. The Fund Group – Woodland Pipeline Extension $0.7 billion $0.7 billion 2015 Complete 17. The Fund Group – Sunday Creek Terminal Expansion $0.2 billion $0.2 billion 2015 Complete 18. The Fund Group – Edmonton to Hardisty Expansion $1.6 billion $1.6 billion 2015 Complete (in phases) 19. The Fund Group – AOC Hangingstone Lateral $0.2 billion $0.2 billion 2015 Complete 20. The Fund Group – JACOS Hangingstone Project $0.2 billion $0.1 billion 2016 Under construction 21. The Fund Group – Regional Oil Sands Optimization Project $2.6 billion $1.6 billion 2017 Under construction 3 22. The Fund Group – Norlite Pipeline System $1.3 billion $0.2 billion 2017 Under construction 23. The Fund Group – Canadian Line 3 Replacement Program $4.9 billion $0.9 billion 2019 Pre-construction 24. EEP – Beckville Cryogenic Processing Facility US$0.2 billion US$0.2 billion 2015 Complete 4 25. EEP – Eastern Access US$2.7 billion US$2.4 billion 2013 – 2016 Under construction (in phases) 4 26. EEP – Lakehead System Mainline Expansion US$2.4 billion US$2.0 billion 2014 – 2019 Under construction (in phases) 27. EEP – Eaglebine Gathering US$0.2 billion US$0.1 billion 2015 – TBD Complete(Phase I) (in phases) 5 28. EEP – Sandpiper Project US$2.6 billion US$0.7 billion 2019 Pre-construction 29. EEP – U.S. Line 3 Replacement Program US$2.6 billion US$0.3 billion 2019 Pre-construction 1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect Enbridge’s share of joint venture projects. 2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to December 31, 2015. 3 The Company will construct and operate the Norlite Pipeline System (Norlite). Keyera Corp. (Keyera) will fund 30%of the project. 4 The Eastern Access and Lakehead System Mainline Expansion projects are funded 75% by Enbridge and 25% by EEP. 5 The Company will construct and operate Sandpiper. Marathon Petroleum Corporation (MPC) will fund 37.5% of the project. Risks related to the development and completion of growth projects are described under Risk Management and Financial Instruments – General Business Risks. 36 Enbridge Inc. 2015 Annual Report
Norman Wells CANADA Zama Fort McMurray Cheecham Edmonton Hardisty Blaine Portland Montreal Superior Toronto Sarnia UNITED STATES OF AMERICA Buffalo Chicago Toledo 1 Patoka Wood River Cushing M E New Orleans X Houston IC 0 Liquids Pipelines 1 Southern Access Extension Current Assets Growth Projects 1 The Fund Group The Fund Group Legacy Assets Enbridge Energy Partners, L.P. 1 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business to the Fund Group within Sponsored Investments. For further details, refer to Canadian Restructuring Plan. Management’s Discussion & Analysis 37
Liquids Pipelines Southern Access Extension The Southern Access Extension joint venture involved the construction of a new 265-kilometre (165-mile), 24-inch diameter crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, for an initial capacity of approximately 300,000 bpd, as well as additional tankage and two new pump stations. The project was placed into service in December 2015 and the Company’s share of the total capital cost was approximately US$0.6 billion. Gas Distribution Greater Toronto Area Project EGD is undertaking the expansion of its natural gas distribution system in the GTA to meet the demands of growth and to continue the safe and reliable delivery of natural gas to current and future customers. The GTA project involves the construction of two new segments of pipeline, a 27-kilometre (17-mile), 42-inch diameter pipeline (Western segment) and a 23-kilometre (14-mile), 36-inch diameter pipeline (Eastern segment), both of which are now expected to enter service by the end of the first quarter of 2016, as well as related facilities to upgrade the existing distribution system in Toronto, Ontario, that delivers natural gas to several municipalities in the GTA. The project is now expected to cost approximately $0.9 billion due to greater complexity in the construction and requirements from government and permitting agencies. Expenditures incurred to date are approximately $0.8 billion. Gas Pipelines, Processing and Energy Services Keechi Wind Project In 2014, Enbridge announced it had entered into an agreement with Renewable Energy Systems Americas Inc. (RES Americas) to own and operate the 110-MW Keechi, located in Jack County, Texas. The project was constructed by RES Americas under a fixed price, engineering, procurement and construction agreement at a total cost of approximately US$0.2 billion, and it entered service in January 2015. The electricity generated by Keechi is delivered into the Electric Reliability Council of Texas, Inc. market under a 20-year PPA with Microsoft Corporation. Walker Ridge Gas Gathering System The Company has agreements with Chevron USA Inc. (Chevron) and Union Oil Company of California, and their co-owners, to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, the Company has constructed and will own and operate the WRGGS to provide natural gas gathering services to the Chevron operated Jack St. Malo and Big Foot ultra-deep water developments. The WRGGS includes 274 kilometres (170 miles) of 8-inch or 10-inch diameter pipeline at depths of up to approximately 2,150 metres (7,000 feet), with capacity of 100 million cubic feet per day (mmcf/d). The Jack St. Malo portion of the WRGGS was placed into service in December 2014. The Big Foot Gas Pipeline portion of the WRGGS has been installed on the sea floor and is awaiting Big Foot platform installation, which has been delayed due to installation problems experienced by Chevron. Chevron continues to investigate the extent of the delay. The Company began collecting certain fees in the fourth quarter of 2015. The total WRGGS project is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.3 billion. Ottawa 2 Toronto Buffalo Sarnia Toledo Gas Distribution 2 Greater Toronto Area Project 38 Enbridge Inc. 2015 Annual Report
7 CANADA Calgary Calgary Montreal Superior Toronto UNITED STATES Sarnia OF AMERICA Chicago Toledo Denver 8 Las Vegas 9 Cushing 3 UNITED M KINGDOM E New Orleans Houston XI London C0 Brighton and Hove 4 5 6 10 11 English Channel Gas Pipelines, Processing and Energy Services Gas Pipelines, Processing and 3 Keechi Wind Project 4 Walker Ridge Gas Gathering System 5 Big Foot Oil Pipeline 6 Heidelberg Oil Pipeline 7 Tupper Main and Tupper West Gas Plants Services 8 Aux Sable Extraction Plant Expansion 9 New Creek Wind Project 10 Stampede Oil Pipeline 11 Rampion Offshore Wind Project Current Assets Growth Projects Wind Assets 1 Wind Assets—The Fund Group The Fund Group Legacy Assets Solar Assets Gas Assets Growth Gas Assets 1 Effective September 1, 2015, Enbridge transferred certain Canadian renewable energy assets to the Fund Group within Sponsored Investments. For further details, refer to Canadian Restructuring Plan. Management’s Discussion & Analysis 39
Big Foot Oil Pipeline Under agreements with Chevron, Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc., the Company has completed the installation on the sea floor of a 64-kilometre (40-mile), 20-inch oil pipeline with a capacity of 100,000 bpd from Chevron’s Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil pipeline project is complementary to the Company’s undertaking of the WRGGS construction, discussed above. Upon completion of the project, the Company will operate the Big Foot Pipeline, located approximately 274 kilometres (170 miles) south of the coast of Louisiana. As noted above, although the Big Foot ultra-deep water development has been delayed, the Company began collecting certain fees in the fourth quarter of 2015. The estimated capital cost of the project is approximately US$0.2 billion, with expenditures to date of approximately US$0.2 billion. Heidelberg Oil Pipeline The Company constructed and owns and operates a crude oil pipeline in the Gulf of Mexico which connects the Heidelberg development, operated by Anadarko Petroleum Corporation, to an existing third party system. Heidelberg Pipeline, a 58-kilometre (36-mile), 20-inch diameter pipeline with capacity of 100,000 bpd, originates in Green Canyon Block 860, approximately 320 kilometres (200 miles) southwest of New Orleans, Louisiana at an estimated depth of 1,600 metres (5,300 feet). Heidelberg Pipeline was placed into service in January 2016 at an approximate cost of US$0.1 billion. Tupper Main and Tupper West Gas Plants In January 2016, Enbridge announced the acquisition of the Tupper Main and Tupper West gas plants (the Tupper Plants) and associated pipelines from a Canadian subsidiary of Murphy Oil Corporation (Murphy Oil) for a purchase price of approximately $0.5 billion. The Tupper Plants have a combined total licensed capacity of 320 mmcf/d and are located within the Montney gas play, 35 kilometres southwest of Dawson Creek, British Columbia, adjacent to Enbridge’s existing Sexsmith gathering system and close to the Alliance Pipeline which is 50% owned by the Fund Group. These assets, including 53 kilometres of high pressure pipelines, are currently in operation and are underpinned by long-term take-or-pay contracts. The purchase price will initially be funded from available sources of liquidity and the acquisition, subject to regulatory review and approval, is anticipated to close by the second quarter of 2016. Aux Sable Extraction Plant Expansion In 2014, the Company approved the expansion of fractionation capacity and related facilities at the Aux Sable extraction and fractionation plant located in Channahon, Illinois. The expansion will serve the growing NGL-rich gas stream on the Alliance Pipeline, allow for effective management of Alliance Pipeline’s downstream natural gas heat content and support additional production and sale of NGL products. The expansion is expected to provide approximately 24,500 bpd of incremental fractionation capacity and is expected to be placed into service in the second quarter of 2016. The Company’s share of the project cost is approximately US$0.1 billion. New Creek Wind Project In November 2015, Enbridge announced it had acquired a 100% interest in the 103-MW New Creek, located in Grant County, West Virginia, from EverPower Wind Holdings, LLC. Enbridge’s total investment is expected to be approximately US$0.2 billion. New Creek will comprise 49 Gamesa turbines and is targeted to be in service in December 2016. The project will be constructed under a fixed-price engineering, procurement and construction agreement, with White Construction Inc. Gamesa will provide turbine operations and maintenance services under a five-year fixed price contract. The project is backed by renewable energy credit sales and medium and long-term offtake agreements. Stampede Oil Pipeline In January 2015, Enbridge announced that it will build, own and operate a crude oil pipeline in the Gulf of Mexico to connect the planned Stampede development, which is operated by Hess Corporation, to an existing third party pipeline system. The Stampede Pipeline, a 26-kilometre (16-mile), 18-inch diameter pipeline with capacity of approximately 100,000 bpd, will originate in Green Canyon Block 468, approximately 350 kilometres (220 miles) southwest of New Orleans, Louisiana, at an estimated depth of 1,200 metres (3,900 feet). Stampede Pipeline is expected to be completed at an approximate cost of US$0.2 billion and is expected to be placed into service in 2018. Rampion Offshore Wind Project In November 2015, Enbridge announced the acquisition of a 24.9% interest in the 400-MW Rampion Project in the United Kingdom, located 13 kilometres (8 miles) off the Sussex coast in the United Kingdom at its nearest point. The Company’s total investment in the project through construction is expected to be approximately $0.8 billion (Ł0.37 billion). The Rampion Project was developed and is being constructed by E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE (E.ON). Construction of the wind farm began in September 2015 and it is expected to be fully operational in 2018. The Rampion Project is backed by revenues from the United Kingdom’s fixed price Renewable Obligation certificates program and a 15-year PPA. Under the terms of the agreement, Enbridge became one of the three shareholders in Rampion Offshore Wind Limited which owns the Rampion Project with the United Kingdom’s Green Investment Bank plc holding a 25% interest and E.ON retaining the balance of 50.1% interest. Enbridge has incurred costs to date of approximately $0.2 billion (Ł0.10 billion). 40 Enbridge Inc. 2015 Annual Report
Sponsored Investments As part of the Canadian Restructuring Plan, the commercially secured growth programs embedded within EPI and EPAI were transferred to the Fund Group and are now presented in Sponsored Investments. Enbridge continues to oversee the execution of the growth program, as well as manage the operations and future development opportunities of these assets. Reference to “the Company” in this Sponsored Investments section includes activities performed by the Fund Group, or on its behalf by Enbridge, following the completion of the Canadian Restructuring Plan. The Fund Group Eastern Access The Eastern Access initiative includes a series of Enbridge and EEP crude oil pipeline projects to provide increased access to refineries in the upper midwest United States and eastern Canada. Projects undertaken by the Company include a reversal of Line 9A and expansion of the Toledo Pipeline, both completed in 2013, as well as the reversal of Line 9B and expansion of Line 9 (together, Line 9), which was placed into service in December 2015. For discussion on EEP’s portion of Eastern Access, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access. The Company completed the reversal of its 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in that province. The Line 9B reversal was initially expected to be completed at an estimated cost of approximately $0.3 billion. Following an open season held on the Line 9B reversal project, further commitments were received that required additional delivery capacity into Ontario and Quebec, resulting in the Line 9 capacity expansion project. The Line 9 capacity expansion increased the annual capacity of Line 9 from 240,000 bpd to 300,000 bpd at an estimated cost of approximately $0.1 billion. The Line 9B Reversal and Line 9 Capacity Expansion projects were approved by the National Energy Board (NEB) in March 2014 subject to 30 conditions. In October 2014, the NEB requested additional information regarding one of the conditions imposed on the Line 9B Reversal and Line 9 Capacity Expansion Project. On October 23, 2014, the Company responded to the NEB describing the Company’s rigorous approach to risk management and isolation valve placement. On February 6, 2015, the NEB approved Conditions 16 and 18, the two conditions in the NEB’s order requiring approval, and the Company filed for a Leave to Open (LTO), which is a prerequisite to allowing the operation of the project. In its February approval, the NEB also imposed additional obligations on the Company that directed the Company to take a “life-cycle” approach to water crossings and valves, requiring it to perform ongoing analysis to ensure optimal protection of the area’s water resources. On June 18, 2015, the NEB approved the LTO application and issued a separate order imposing further conditions requiring the Company to perform hydrostatic tests of selected segments of the pipeline. The Company filed its hydrostatic test plan with the NEB on July 23, 2015, which was approved on July 27, 2015. Hydrostatic testing was completed and the Company submitted the test results to the NEB in September 2015. On September 30, 2015 the NEB confirmed that the hydrostatic tests successfully met their criteria. Line-fill commenced in late October 2015 and the pipeline was placed into service in December 2015. Costs related to conditions imposed by the NEB, including valve placement and hydrostatic testing, increased the total project cost at in-service to $0.8 billion, inclusive of costs related to the previously mentioned Line 9A reversal. Pursuant to various agreements with shippers, the Company is able to recover from shippers the full costs of compliance with NEB imposed hydrostatic testing and the valve replacement program. On July 31, 2014, the Company filed an application for tolls on Line 9. After complaints from shippers on Line 9 were filed with the NEB with respect to the inclusion of mainline surcharges in the Line 9 toll, the NEB approved the tolls on an interim basis to allow for time to engage shippers in further discussions to attempt to resolve the outstanding issues. On January 30, 2015, the NEB convened a hearing to consider the matter. In response to a request from the Company that was supported by the shippers, the hearing was suspended to allow the Company and shippers to engage in further discussions to resolve the outstanding issues. In the third quarter of 2015, the Company and the shippers came to an agreement to recover mainline surcharges in the Line 9 toll. Canadian Mainline Expansion The Company undertook an expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba. The scope of the project consisted of two phases that involved the addition of pumping horsepower to raise the capacity of the Alberta Clipper line from 450,000 bpd to 800,000 bpd. The initial phase to increase capacity from 450,000 bpd to 570,000 bpd was completed in the third quarter of 2014 at an estimated capital cost of approximately $0.2 billion. The second phase to increase capacity from 570,000 bpd to 800,000 bpd was completed in July 2015 at an expected cost of approximately $0.5 billion. The total cost of the entire expansion was approximately $0.7 billion. Receipt of the final regulatory approval on EEP’s portion of the mainline system expansion has been delayed. EEP continues to work with regulatory authorities; however, the timing of the federal regulatory approval cannot be determined at this time. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with this delay. See Growth Projects – Commercially Secured Projects –Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Mainline Expansion. Surmont Phase 2 Expansion In 2013, the Company entered into a terminal services agreement with ConocoPhillips Canada Resources Corp. (ConocoPhillips) and Total E&P Canada Ltd. (together, the ConocoPhillips Partnership) to expand the Cheecham Terminal to accommodate incremental bitumen production from Surmont’s Phase 2 expansion. The Company constructed two new 450,000 barrel blend tanks and converted an existing tank from blend to diluent service. The expansion occurred in two phases with the blended product system placed into service in November 2014 and the diluent system placed into service in March 2015 at a total cost of approximately $0.3 billion. Management’s Discussion & Analysis 41
Canadian Mainline System Terminal Flexibility and Connectivity As part of the Light Oil Market Access Program initiative, the Company undertook the Canadian Mainline System Terminal Flexibility and Connectivity project in order to accommodate additional light oil volumes and enhance the operational flexibility of the Canadian mainline terminals. The modifications comprised of upgrading existing booster pumps, installing additional booster pumps and adding new tank line connections. These projects had varying completion dates from 2013 through the second quarter of 2015. The total cost of the project was approximately $0.7 billion. Woodland Pipeline Extension The joint venture Woodland Pipeline Extension Project extended the Woodland Pipeline south from the Company’s Cheecham Terminal to its Edmonton Terminal. The extension is a 388-kilometre (241-mile), 36-inch diameter pipeline with an initial capacity of 400,000 bpd, expandable to 800,000 bpd. The project was completed and placed into service in July 2015. The Company’s share of the project costs was approximately $0.7 billion. Sunday Creek Terminal Expansion In 2014, the Company announced the construction of additional facilities at its existing Sunday Creek Terminal, located in the Christina Lake area of northern Alberta, to support production growth from the Christina Lake oil sands project operated by Cenovus Energy Inc. and jointly owned with ConocoPhillips. The expansion included development of a new site adjacent to the existing terminal, construction of a new 350,000 barrel tank with associated piping, pumps and measurement equipment, as well as civil construction work for a future tank. The project was placed into service in August 2015 at an approximate cost of $0.2 billion. Edmonton to Hardisty Expansion The expansion of the Canadian Mainline system between Edmonton, Alberta and Hardisty, Alberta included 181 kilometres (112 miles) of new 36-inch diameter pipeline and provides an initial capacity of approximately 570,000 bpd, expandable to 800,000 bpd. The new line generally follows the same route as the Company’s existing Line 4 pipeline. Also included in the project scope were connections into existing infrastructure at the Hardisty Terminal and new terminal facilities in Edmonton, Alberta which include five new 500,000 barrel tanks. The new pipeline was placed into service in April 2015, with additional tankage requirements completed in December 2015. The project was placed into service at a cost of approximately $1.6 billion. AOC Hangingstone Lateral In 2013, the Company entered into an agreement with Athabasca Oil Corporation (AOC) to provide pipeline and terminalling services to the proposed AOC Hangingstone Oil Sands Project (AOC Hangingstone) in Alberta. Phase I of the project involved the construction of a new 49-kilometre (31-mile), 16-inch diameter pipeline from the AOC Hangingstone project site to the Company’s existing Cheecham Terminal and related facility modifications at Cheecham, Alberta. This phase of the project provides an initial capacity of 16,000 bpd and was placed into service in December 2015 at a cost of approximately $0.2 billion. Phase 2 of the project, which is subject to commercial approval, would provide up to an additional 60,000 bpd for a total capacity of 76,000 bpd. JACOS Hangingstone Project The Company is undertaking the construction of facilities and it will provide transportation services to the Japan Canada Oil Sands Limited (JACOS) Hangingstone Oil Sands Project (JACOS Hangingstone). JACOS and Nexen Energy ULC, a wholly-owned subsidiary of China National Offshore Oil Corporation Limited, are partners in the project which is operated by JACOS. The Company is constructing a new 53-kilometre (33-mile), 12-inch lateral pipeline to connect the JACOS Hangingstone project site to the Company’s existing Cheecham Terminal. The project, which will provide capacity of 40,000 bpd, is expected to enter service by the end of 2016. The estimated cost of the project is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion. Regional Oil Sands Optimization Project In March 2015, the Company announced a plan to optimize previously announced expansions of its Regional Oil Sands System currently in execution. The Company previously announced the Wood Buffalo Extension, which includes the construction of a 30-inch pipeline, from the Company’s Cheecham Terminal to its Battle River Terminal at Hardisty, Alberta and associated terminal upgrades, and the Athabasca Pipeline Twin, which consists of the twinning of the southern section of the Athabasca Pipeline with a 36-inch diameter pipeline from Kirby Lake, Alberta to its Hardisty crude oil hub. The optimization plan, which has been agreed to with the affected shippers, including Suncor Energy Inc., Total E&P Canada Ltd. and Teck Resources Limited (the Fort Hills Partners), will enable deferral of the southern segment of the Wood Buffalo Extension by connecting it to the Athabasca Pipeline Twin. The optimization involves the upsize of a 100-kilometre (60-mile) segment of the Wood Buffalo Extension between Cheecham, Alberta and Kirby Lake, Alberta from a 30-inch diameter pipeline to a 36-inch diameter pipeline, which will now connect to the origin of the Athabasca Pipeline Twin at Kirby Lake, Alberta. The capacity of the Athabasca Pipeline Twin will be expanded from 450,000 bpd to 800,000 bpd through additional horsepower. The definitive cost estimate of the Wood Buffalo Extension was finalized at approximately $1.8 billion before optimization. As a result of the optimization, the cost estimate to complete the integrated Wood Buffalo Extension and Athabasca Pipeline Twin projects is expected to decrease from approximately $3.0 billion to approximately $2.6 billion. Expenditures on the joint projects to date are approximately $1.6 billion. The integrated Wood Buffalo Extension and Athabasca Pipeline Twin will transport diluted bitumen from the proposed Fort Hills Partners’ oil sands project (Fort Hills Project) in northeastern Alberta, as well as from oil sands production from Suncor Energy Oil Sands Limited Partnership (Suncor Partnership) in the Athabasca region. The Wood Buffalo Extension and the Athabasca Pipeline Twin will ship blended bitumen from the Fort Hills Project and have an expected 2017 in-service date. The Athabasca Pipeline Twin will also ship blended bitumen from the Cenovus Christina Lake Steam Assisted Gravity Drainage project near the origin of the Athabasca Pipeline Twin. 42 Enbridge Inc. 2015 Annual Report
Fort McMurray 19 20 Cheecham Fort St. John Fort St. John 16 14 Fort McMurray Cheecham 22 17 21 Edmonton Edmonton Hardisty 15 CANADA 18 Calgary 13 Hardisty 23 Gretna Clearbrook Minot 29 28 Montreal Montreal Superior Toronto 26 Sarnia UNITED STATES 12 25 OF AMERICA Chicago Flanagan Patoka Wood River Cushing 24 27 New Orleans Houston ME XI C O Sponsored Investments 12 The Fund Group – Eastern Access (Line 9 Reversal and Expansion) 13 The Fund Group – Canadian Mainline Expansion 14 The Fund Group – Surmont Phase 2 Expansion 15 The Fund Group – Canadian Mainline System Terminal Flexibility and Connectivity 16 The Fund Group – Woodland Pipeline Extension 17 The Fund Group – Sunday Creek Terminal Expansion 18 The Fund Group – Edmonton to Hardisty Expansion 19 The Fund Group – AOC Hangingstone Lateral 20 The Fund Group – JACOS Hangingstone Project 21 The Fund Group – Regional Oil Sands Optimization Project 22 The Fund Group – Norlite Pipeline System 23 The Fund Group – Canadian Line 3 Replacement Program 24 EEP – Beckville Cryogenic Processing Facility 25 EEP – Eastern Access 26 EEP – Lakehead System Mainline Expansion 27 EEP – Eaglebine Gathering 28 EEP – Sandpiper Project 29 EEP – U.S. Line 3 Replacement Program Current Assets Growth Projects 1 The Fund Group Enbridge Inc. Wind Assets 1 Wind Assets—The Fund Group Solar Assets 1 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group within Sponsored Investments. For further details, refer to Canadian Restructuring Plan. Management’s Discussion & Analysis 43
Norlite Pipeline System The Company is undertaking the development of Norlite, a new industry diluent pipeline originating from Edmonton, Alberta to meet the needs of multiple producers in the Athabasca oil sands region. The scope of the project was increased to a 24-inch diameter pipeline, which will provide an initial capacity of approximately 224,000 bpd of diluent, with the potential to be further expanded to approximately 400,000 bpd of capacity with the addition of pump stations. Norlite will be anchored by throughput commitments from the Fort Hills Partners for production from the proposed Fort Hills Project and from Suncor Partnership’s proprietary oil sands production. Norlite will involve the construction of a new 449-kilometre (278-mile) pipeline from the Company’s Stonefell Terminal to its Cheecham Terminal with an extension to Suncor Partnership’s East Tank Farm, which is adjacent to the Company’s existing Athabasca Terminal. Under an agreement with Keyera, Norlite has the right to access certain existing capacity on Keyera’s pipelines between Edmonton, Alberta and Stonefell, Alberta and, in exchange, Keyera has elected to participate in the new pipeline infrastructure project as a 30% non-operating owner. Norlite is expected to be completed in 2017 at an estimated cost of approximately $1.3 billion, with expenditures to date of approximately $0.2 billion. Canadian Line 3 Replacement Program In 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. The Canadian L3R Program will complement existing integrity programs by replacing approximately 1,084 kilometres (673 miles) of the remaining line segments of the existing Line 3 pipeline between Hardisty, Alberta and Gretna, Manitoba. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the overall system, enhance flexibility and allow the Company to optimize throughput on the mainline system’s overall western Canada export capacity. The L3R Program is expected to achieve capacity of approximately 760,000 bpd. With the NEB hearing for the Canadian L3R Program application ending in December 2015, the application record is now closed with Final Conditions and a recommendation to the Federal Cabinet (the Cabinet) expected by the end of the first quarter of 2016. A decision by the Cabinet was expected to be issued by July 2016 per guidelines; however, the Company is awaiting confirmation following the Federal Government’s January 27, 2016 announcement that outside of the NEB process for industry projects, it has directed Federal agencies to conduct assessments of direct and upstream greenhouse gas emissions and incremental consultation with affected communities and Indigenous peoples. Depending on the scope of this new process, the expected timeline for final regulatory approval to commence construction could be extended. The Company has reached a settlement agreement with landowner associations representing Line 3 landowners in Canada and as a result these parties have withdrawn from the hearing process and have expressed their support for the project. Subject to regulatory and other approvals, the Canadian L3R Program is now targeted to be completed in early 2019 at an estimated capital cost of approximately $4.9 billion, with expenditures to date of approximately $0.9 billion. With a delay in construction, the cost of this project is expected to increase. The Company continues to review the estimated cost of this project. Costs of the Canadian L3R Program will be recovered through a 15-year toll surcharge mechanism under the CTS. For discussion on EEP’s portion of the L3R Program, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – United States Line 3 Replacement Program. Enbridge Energy Partners, L.P. Beckville Cryogenic Processing Facility EEP and its partially-owned subsidiary, MEP, have constructed a cryogenic natural gas processing plant near Beckville (the Beckville Plant) in Panola County, Texas. The Beckville Plant offers incremental processing capacity for existing and future customers in the 10-county Cotton Valley shale region, where the East Texas system is located. The Beckville Plant has a natural gas processing capability of 150 mmcf/d and is expected to produce 8,500 bpd of NGL. The Beckville Plant was placed into service in May 2015 at a cost of approximately US$0.2 billion. Eastern Access The Eastern Access initiative includes a series of Enbridge and EEP crude oil pipeline projects to provide increased access to refineries in the upper midwest United States and eastern Canada. Projects undertaken by EEP included an expansion of Line 5 and of the United States mainline involving the Spearhead North Pipeline (Line 62), both completed in 2013, and replacement of additional segments of Line 6B, completed in 2014. The cost of these projects was approximately US$2.4 billion. For discussion on the Company’s portion of Eastern Access, refer to Growth Projects – Commercially Secured Projects –Sponsored Investments – The Fund Group –Eastern Access. Additionally, the Eastern Access initiative also includes a further upsizing of EEP’s Line 6B. The Line 6B capacity expansion from Griffith, Indiana to Stockbridge, Michigan will increase capacity from 500,000 bpd to 570,000 bpd and will include pump station modifications at the Griffith, Niles and Mendon stations, additional modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. The Line 6B capacity expansion is now expected to be placed into service in mid-2016 at an estimated cost of approximately US$0.3 billion. The total estimated cost of the projects being undertaken by EEP as part of the Eastern Access initiative, including the Line 6B capacity expansion project, is approximately US$2.7 billion, with expenditures to date of approximately US$2.4 billion. The Eastern Access projects undertaken by EEP are being funded 75% by Enbridge and 25% by EEP. Within one year of the final in-service date of the collective projects, EEP will have the option to increase its economic interest held at that time by up to an additional 15%. On July 30, 2015, Enbridge and EEP reached an agreement to forego distributions to EELP for its interests in the Eastern Access projects 44 Enbridge Inc. 2015 Annual Report
until the second quarter of 2016. EELP holds partnership interests in assets that are jointly funded by Enbridge and EEP, including the Eastern Access projects. In return, Enbridge’s capital funding contribution requirements to the Eastern Access projects will be netted against its foregone cash distribution during this period. Lakehead System Mainline Expansion The Lakehead System Mainline Expansion includes several projects to expand capacity of the Lakehead System mainline between its origin at the Canada/United States border, near Neche, North Dakota to Flanagan, Illinois. These projects are in addition to expansions of the Lakehead System mainline being undertaken as part of the Eastern Access initiative and include the expansion of Alberta Clipper (Line 67) and Southern Access (Line 61) and the construction of the Spearhead North Twin (Line 78). The current scope of the Alberta Clipper expansion between the border and Superior, Wisconsin consists of two phases. The initial phase increased capacity from 450,000 bpd to 570,000 bpd at an estimated capital cost of approximately US$0.2 billion. The second phase increased capacity from 570,000 bpd to 800,000 bpd at an estimated capital cost of approximately US$0.2 billion. The initial phase was completed in the third quarter of 2014 and the second phase was completed in July 2015. Both phases of the Alberta Clipper expansion required only the addition of pumping horsepower with no pipeline construction and are subject to regulatory approvals, including an amendment to the current Presidential border crossing permit to allow for operation of Line 67 at its currently planned operating capacity of 800,000 bpd. EEP continues to work with regulatory authorities; however, the timing of receipt of the amendment to the Presidential border crossing permit to allow for increased flow on Alberta Clipper across the border cannot be determined at this time. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with any delays in obtaining this amendment. In November 2014, several environmental and Native American groups filed a complaint in the United States District Court in Minnesota (the Court) against the United States Department of State (DOS). The Complaint alleges, among other things, that the DOS is in violation of the United States’ National Environmental Policy Act by acquiescing in the Company’s use of permitted cross border capacity on other pipelines to achieve the transportation of amounts in excess of Alberta Clipper’s current permitted capacity while the review and approval of the Company’s application to the DOS to increase Alberta Clipper’s permitted cross border capacity is still pending. On December 9, 2015 the Court ruled that the United States’ State Department’s interpretation of Enbridge’s Presidential permits is not reviewable by a federal court on constitutional grounds. The scope of the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois also consists of phases that require only the addition of pumping horsepower with no pipeline construction. The initial phase to increase the capacity from 400,000 bpd to 560,000 bpd was completed in August 2014 at an estimated capital cost of approximately US$0.2 billion. EEP further expanded the pipeline capacity to 800,000 bpd in May 2015 at an estimated capital cost of approximately US$0.4 billion. Additional tankage is expected to cost approximately US$0.4 billion with various completion dates that began in the third quarter of 2015 and are expected to continue through the third quarter of 2016. In the first quarter of 2015, the Company, in conjunction with shippers, decided to delay the in-service date of a further expansion phase to increase the pipeline capacity to 1,200,000 bpd at an estimated capital cost of approximately US$0.5 billion, to align more closely with the anticipated in-service date for Sandpiper. In October 2015, a portion of this phase was placed into service early to address capacity constraints, increasing the pipeline capacity to 950,000 bpd. The remaining capacity is now expected to be in service in early 2019 in line with the expected in-service date of Sandpiper. As part of the Light Oil Market Access Program, EEP expanded the capacity of the Lakehead System between Flanagan, Illinois and Griffith, Indiana by constructing a 127-kilometre (79-mile), 36-inch diameter twin of the existing Spearhead North Pipeline (Line 62), with an initial capacity of 570,000 bpd. The completed Spearhead North Twin (Line 78) project was placed into service in November 2015 at a cost of approximately US$0.5 billion. The projects collectively referred to as the Lakehead System Mainline Expansion are now expected to cost approximately US$2.4 billion, with expenditures incurred to date of approximately US$2.0 billion. EEP will operate the project on a cost-of-service basis. The Lakehead System Mainline Expansion is funded 75% by Enbridge and 25% by EEP. EEP has the option to increase its economic interest held by up to an additional 15% at cost. On July 30, 2015, Enbridge and EEP reached an agreement to forego distributions to EELP for its interests in the Lakehead System Mainline Expansion until the second quarter of 2016. EELP holds partnership interests in assets that are jointly funded by Enbridge and EEP, including the Lakehead System Mainline Expansion. In return, Enbridge’s capital funding contribution requirements to the Lakehead System Mainline Expansion will be netted against its foregone cash distribution during this period. Eaglebine Gathering In February 2015, EEP and MEP announced their entry into the emerging Eaglebine shale play in East Texas through two transactions totalling approximately US$0.2 billion. EEP and MEP completed construction of the Ghost Chili pipeline project, consisting of a lateral and associated facilities that create gathering capacity of over 50 mmcf/d for rich natural gas to be delivered from Eaglebine production areas to their complex of cryogenic processing facilities in East Texas. The initial facilities were placed into service in October 2015. EEP also expects to construct the Ghost Chili Extension Lateral to fully utilize the gathering capacity with the rest of EEP’s processing assets when additional development in the basin supports it. Given the proximity of EEP’s existing East Texas assets, this expansion into Eaglebine will allow EEP to offer gathering and processing services while leveraging assets on its existing footprint. MEP also acquired New Gulf Resources, LLC’s midstream business in Leon, Madison and Grimes Counties, Texas. The acquisition consists of a natural gas gathering system that is currently in operation. Expenditures incurred to date are approximately US$0.1 billion. Management’s Discussion & Analysis 45
Sandpiper Project As part of the Light Oil Market Access Program initiative, EEP plans to undertake Sandpiper, which will expand and extend EEP’s North Dakota feeder system. The Bakken takeaway capacity of the North Dakota System will be expanded by 225,000 bpd to a total of 580,000 bpd. The proposed expansion will involve construction of a 965-kilometre (600-mile) line from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line will twin the existing 210,000 bpd North Dakota System mainline, which now terminates at Clearbrook Terminal in Minnesota, by adding 250,000 bpd of capacity between Tioga and Berthold, North Dakota and 225,000 bpd of capacity between Berthold and Clearbrook, both with new 24-inch diameter pipelines, as well as adding 375,000 bpd of capacity between Clearbrook and Superior with a new 30-inch diameter pipeline. EEP is in the process of obtaining the appropriate permits for constructing Sandpiper in Minnesota. The project requires both a Certificate of Need and Route Permit from the Minnesota Public Utilities Commission (MNPUC). On August 3, 2015, the MNPUC issued an order granting a Certificate of Need and a separate order restarting the Route Permit proceedings. On September 14, 2015 the Minnesota Court of Appeals reversed the MNPUC’s Certificate of Need order stating that an Environmental Impact Statement must be prepared prior to reaching a final decision in cases where proceedings have been separated and handled sequentially. On January 11, 2016 the MNPUC issued a written order (the Sandpiper Order) re-joining the Certificate of Need and Route Permit process, requiring the Department of Commerce to commence preparation of an Environmental Impact Statement, ordering the Office of Administrative Hearings to recommence processing the Certificate of Need and Route Permit applications but to take judicial notice of the record already developed for the Certificate of Need, and to require that a final Environmental Impact Statement be issued before the Certificate of Need and Route Permit processes commence. The Company believes that the directions from the MNPUC in most of the decisions set out in the Sandpiper Order were consistent with expectations and provide clarity on process matters; however, Enbridge believes that the requirement to have a final Environmental Impact Statement prior to beginning the Certificate of Need and Route Permit processes is unprecedented and contrary to Minnesota law. On February 1, 2016, EEP filed a Petition for Reconsideration of this aspect of the Sandpiper Order. If upheld, the Sandpiper Order will result in delays in the processing of the applications and an increase in the cost of the project. Subject to regulatory and other approvals, Sandpiper is now expected to be completed in early 2019 at an estimated capital cost of approximately US$2.6 billion, with expenditures incurred to date of approximately US$0.7 billion. The Company continues to review the impact of the Sandpiper Order on the project’s schedule and cost estimates. MPC has been secured as an anchor shipper for Sandpiper. As part of the arrangement, EEP, through its subsidiary, North Dakota Pipeline Company LLC (NDPC) (formerly known as Enbridge Pipelines (North Dakota) LLC), and Williston Basin Pipeline LLC (Williston), an affiliate of MPC, entered into an agreement to, among other things, admit Williston as a member of NDPC. Williston will fund 37.5% of Sandpiper construction and will have the option to participate in other growth projects within NDPC, unless specifically excluded by the agreement; this investment is not to exceed US$1.2 billion in aggregate. In return for funding part of Sandpiper’s construction, Williston will obtain an approximate 27% equity interest in NDPC at the in-service date of Sandpiper. United States Line 3 Replacement Program In 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. EEP expects to undertake the United States portion of the L3R Program (U.S. L3R Program) which will complement existing integrity programs by replacing approximately 576 kilometres (358 miles) of the remaining line segments of the existing Line 3 pipeline between Neche, North Dakota and Superior, Wisconsin. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the overall system, enhance flexibility and allow the Company to optimize throughput on the mainline system’s overall western Canada export capacity. The L3R Program is expected to achieve capacity of approximately 760,000 bpd. The MNPUC found both the Certificate of Need and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. The MNPUC had sent the Certificate of Need application to the Administrative Law Judge (ALJ) for a pre-hearing meeting to establish a schedule. With respect to the Route Permit, the Minnesota Department of Commerce held public scoping meetings in August 2015. As a result of the Court of Appeals decision in the Sandpiper docket, the ALJ requested direction on how to proceed with the Certificate of Need process for Line 3. On February 1, 2016 the MNPUC issued a written order (the U.S. L3R Order) joining the Line 3 Certificate of Need and Route Permit dockets, requiring the Department of Commerce to prepare an Environmental Impact Statement before Certificate of Need and Route Permit processes commence and sent the cases to the Office of Administrative Hearings with direction to re-start the process. The Company believes that the directions from the MNPUC in most of the decisions set out in the U.S. L3R Order were consistent with expectations and provide clarity on process matters; however, Enbridge believes that the requirement to have a final Environmental Impact Statement prior to beginning the Certificate of need and Route Permit processes is unprecedented and contrary to Minnesota law. On February 5, 2016 EEP filed a Petition for Reconsideration of this aspect of the U.S. L3R Order. If upheld, the U.S. L3R Order will result in further delays in the processing of the applications and an increase in the cost of the project. Subject to regulatory and other approvals, the U.S. L3R Program is now expected to be completed in early 2019 at an estimated capital cost of approximately US$2.6 billion, with expenditures to date of approximately US$0.3 billion. The Company continues to review the impact of the U.S. L3R Order on the U.S. L3R Program’s schedule and cost estimates. The U.S. L3R Program will be jointly funded by Enbridge and EEP at participation levels that are subject to finalization. EEP will recover the costs based on its existing Facilities Surcharge Mechanism with the initial term of the agreement being 15 years. For the purpose of the toll surcharge, the agreement specifies a 30-year recovery of the capital based on a cost of service methodology. 46 Enbridge Inc. 2015 Annual Report
Other Announced Projects Under Development The following projects have been announced by the Company, but have not yet met the Company’s criteria to be classified as commercially secured. The Company also has additional attractive projects under development that have not yet progressed to the point of public announcement. In its long-term funding plans, the Company makes full provision for all commercially secured projects and makes provision for projects under development based on an assessment of the aggregate securement success anticipated. Actual securement success achieved could exceed or fall short of the anticipated level. Liquids Pipelines Northern Gateway Project Northern Gateway involves constructing a twin 1,178-kilometre (731-mile) pipeline system from near Edmonton, Alberta to a new marine terminal in Kitimat, British Columbia. One pipeline would transport crude oil for export from the Edmonton area to Kitimat and is proposed to be a 36-inch diameter line with an initial capacity of 525,000 bpd. The other pipeline would be used to transport imported condensate from Kitimat to the Edmonton area and is proposed to be a 20-inch diameter line with an initial capacity of 193,000 bpd. In 2010, Northern Gateway submitted an application to the NEB and the Joint Review Panel (JRP) was established to review the proposed project, pursuant to the NEB Act and the Canadian Environmental Assessment Act. The JRP had a broad mandate to assess the potential environmental effects of the project and to determine if development of Northern Gateway was in the public interest. In December 2013, the JRP issued its report on Northern Gateway. The report found that the petroleum industry is a significant driver of the Canadian economy and an important contributor to the Canadian standard of living and noted that the benefits of Northern Gateway outweigh its burdens and that “Canadians would be better off with the Enbridge Northern Gateway Project than without it.” The Government of Canada consulted with Aboriginal groups on the JRP report and its recommendations prior to making its decision on whether to direct the NEB to issue the Certificates of Public Convenience and Necessity for the pipelines. In June 2014, the Governor in Council approved Northern Gateway, subject to 209 conditions following the recommendation from the JRP. The Company continues to work closely with its customers in advancing this project to open West Coast market access and is making progress in fulfilling the conditions and building relationships and trust with communities and Aboriginal groups along the proposed route. Nine applications to the Federal Court of Appeal (Federal Court) for leave for judicial review of the Order in Council were filed in July 2014. The applicants made two basic arguments in seeking leave. First, they argued that the JRP report and the Order in Council contain evidentiary gaps or gaps in reasoning. Second, they alleged that the Crown failed to discharge its constitutional duty to consult and, if appropriate, accommodate the Aboriginal applicants. The Federal Court consolidated the nine applications into one proceeding. The hearing of these applications commenced in Vancouver, British Columbia, on October 1, 2015 and concluded on October 8, 2015. Depending on the outcome of these proceedings, which is anticipated for 2016, an application for Leave to Appeal to the Supreme Court of Canada is a possibility. The Company reviewed an updated cost estimate of Northern Gateway based on full engineering analysis of the pipeline route and terminal location. Based on this comprehensive review, the Company expects that the final cost of the project will be substantially higher than the preliminary cost figures included in the Northern Gateway filing with the JRP, which reflected a preliminary estimate prepared in 2004 and escalated to 2010. The drivers behind this substantial increase include the significant costs associated with escalation of labour and construction costs, satisfying the 209 conditions imposed in the Governor in Council approval, a larger portion of high cost pipeline terrain, more extensive terminal site rock excavations and a delayed anticipated in-service date. The updated cost estimate is currently being assessed and refined by Northern Gateway and the potential shippers. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.6 billion, of which approximately half is being funded by potential shippers on Northern Gateway. The in-service date of the project will be dependent upon the timing and outcome of judicial reviews, continued commercial support, receipt of regulatory and other approvals and adequately addressing landowner and local community concerns (including those of Aboriginal communities). Of the 48 Aboriginal groups eligible to participate as equity owners, 28 have signed up to do so. Given the many uncertainties surrounding Northern Gateway, including final ownership structure, the potential financial impact of the project cannot be determined at this time. The JRP posts public filings related to Northern Gateway on its website at http://gatewaypanel.review-examen.gc.ca/clf-nsi/hm-eng.html and Northern Gateway also maintains a website at northerngateway.ca where the full regulatory application submitted to the NEB, the 2010 Enbridge Northern Gateway Community Social Responsibility Report and the December 19, 2013 Report of the JRP on the Northern Gateway Application are available. Unless otherwise specifically stated, none of the information contained on, or connected to, the JRP website or the Northern Gateway website is incorporated by reference in, or otherwise part, of this MD&A. Gas Pipelines, Processing and Energy Services NEXUS Gas Transmission Project In 2012, Enbridge, DTE Energy Company (DTE) and Spectra Energy Corp. (Spectra) announced the execution of a Memorandum of Understanding (MOU) to jointly develop the NEXUS Gas Transmission System, a project that would move growing supplies of Ohio Utica shale gas to markets in the United States midwest, including Ohio and Michigan, and Ontario, Canada. The MOU has expired and Enbridge is in discussions with Spectra and DTE regarding terms for its potential participation in the project. Management’s Discussion & Analysis 47
Liquids Pipelines Earnings 2015 2014 2013 (millions of Canadian dollars) Canadian Mainline 395 500 460 Regional Oil Sands System 108 181 170 Seaway and Flanagan South Pipelines 103 74 48 Spearhead Pipeline 34 31 31 Southern Lights Pipeline 11 49 49 Feeder Pipelines and Other 40 23 12 Adjusted earnings 691 858 770 Canadian Mainline – changes in unrealized derivative fair value loss (819) (370) (268) Canadian Mainline – Line 9B costs incurred during reversal (5) (8) – Canadian Mainline–write-off of regulatory asset in respect of taxes (88) –– Canadian Mainline – impact of tax rate changes 9 –– Regional Oil Sands System–make-up rights adjustment 9 6(13) Regional Oil Sands System – leak insurance recoveries 9 8– Regional Oil Sands System – leak remediation and long-term pipeline stabilization costs (5) (4) (56) Regional Oil Sands System–impact of tax rate changes (31) –– Regional Oil Sands System–loss on disposal of non-core assets (7) –– Regional Oil Sands System – prior period adjustment 16 –– Regional Oil Sands System – make-up rights out-of-period adjustment – –(37) Regional Oil Sands System – long-term contractual recovery out-of-period adjustment, net – –31 Seaway and Flanagan South Pipelines–make-up rights adjustment (35) (25) – Spearhead Pipeline – make-up rights adjustment 1 –– Spearhead Pipeline – changes in unrealized derivative fair value gains/(loss) (1) 1– Feeder Pipelines and Other – gain on sale of non-core assets 44 –– Feeder Pipelines and Other – make-up rights adjustment (3) 3– Feeder Pipelines and Other – project development costs (5) (6) – Feeder Pipelines and Other – impact of tax rate changes (4) –– Earnings/(loss) attributable to common shareholders (224) 463 427 Liquids Pipelines adjusted earnings were $691 million in 2015 compared with adjusted earnings of $858 million in 2014 and $770 million in 2013. Liquids Pipelines adjusted earnings for the year ended December 31, 2015 are impacted by the effects of the transfer of interests in Southern Lights Pipeline in November 2014 and September 2015 and the transfer of Canadian Mainline and Regional Oil Sands System under the Canadian Restructuring Plan effective September 1, 2015. Following the transfers to the Fund Group, the results of these assets are no longer reported in the Liquids Pipelines segment, but are captured in the results of the Fund Group which are reported within Sponsored Investments. Prior to the closing of the Canadian Restructuring Plan effective September 1, 2015, the Company continued to realize growth on Canadian Mainline primarily due to higher throughput that resulted from strong oil sands production in western Canada combined with strong downstream refinery demand, as well as successful efforts by the Company to optimize capacity and throughput and to enhance scheduling efficiency with shippers. These positive effects on Canadian Mainline were partially offset by a lower year-over-year average Canadian Mainline IJT Residual Benchmark Toll. In 2015, the Company benefitted from the full-year operation of Flanagan South and Seaway Pipeline Twin, which commenced in late 2014. Adjusted earnings from Regional Oil Sands System, however, decreased due to a reduction in contracted volumes on the Athabasca Mainline. Additional details on items impacting Liquids Pipelines include: Canadian Mainline earnings/(loss) for each period reflected changes in unrealized fair • value losses on derivative financial instruments used to manage risk exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices. Liquids Pipelines Earnings (millions of Canadian dollars) 858 770 697 691 655 470 501 463 427 (224) 11 12 13 14 15 ? GAAP Earnings ? Adjusted Earnings 48 Enbridge Inc. 2015 Annual Report
Liquids Pipelines Norman Wells NW System Zama Fort McMurray Cheecham Waupisoo Pipeline Athabasca System Edmonton Hardisty CANADA Blaine Enbridge Mainline System Olympic Pipeline Portland Gretna Saskatchewan System Lakehead System Enbridge North Dakota System Mainline System Montreal Superior Toronto UNITED STATES Sarnia Buffalo OF AMERICA Toledo Pipeline Chicago Toledo Southern Access Mustang and Extension Pipeline Chicap Pipeline Flanagan South and Patoka Spearhead Pipeline Pipeline Cushing Ozark Pipeline Seaway Crude M Pipeline System E Enbridge Inc. 1 X The Fund Group I C The Fund Group Legacy Assets O Enbridge Energy Partners, L.P. 1 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business to the Fund Group within Sponsored Investments. For further details, refer to Canadian Restructuring Plan. Management’s Discussion & Analysis 49 •
Canadian Mainline earnings/(loss) for 2015 and 2014 included depreciation and interest expenses charged to Line 9B while it was idled and undergoing a reversal as part of the Company’s Eastern Access initiative. • Canadian Mainline loss for 2015 included a write-off of a regulatory asset in respect of taxes resulting from the transfer of assets between entities under common control of Enbridge in conjunction with the Canadian Restructuring Plan. • Regional Oil Sands System earnings for each period included make-up rights adjustments to recognize revenue for certain long-term take-or-pay contracts rateably over the contract life. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. Generally, under such take-or-pay contracts, payments are received rateably over the life of the contract as capacity is provided, regardless of volumes shipped, and are non-refundable. Should make-up rights be utilized in future periods, costs associated with such transportation service are typically passed through to shippers, such that little or no cost is borne by Enbridge. For the purposes of adjusted earnings, the Company reflects contributions from these contracts rateably over the life of the contract, consistent with contractual cash payments under the contract. • Regional Oil Sands System earnings for each period included charges, before insurance recoveries, related to the Line 37 crude oil release, which occurred in June 2013. Refer to Liquids Pipelines – Regional Oil Sands System – Line 37 Crude Oil Release. • Regional Oil Sands System earnings for 2015 and 2014 included insurance recoveries associated with the Line 37 crude oil release, which occurred in June 2013. Refer to Liquids Pipelines – Regional Oil Sands System – Line 37 Crude Oil Release. • Regional Oil Sands System earnings for 2013 included an out-of-period, non-cash adjustment to defer revenues associated with make-up rights earned under certain long-term take-or-pay contracts. • Regional Oil Sands System earnings for 2013 included an out-of-period, non-cash adjustment to correct deferred income tax expense and to correct the rate at which deemed taxes are recovered under a long-term contract. • Earnings/(loss) for Canadian Mainline, Regional Oil Sands System and Feeder Pipelines and Other included the impact of a corporate tax rate change in the province of Alberta on opening deferred income tax balances. • Feeder Pipelines and Other earnings for 2015 and 2014 included certain business development costs related to Northern Gateway that are anticipated to be recovered over the life of the project. Canadian Mainline The mainline system is comprised of the Canadian Mainline and the Lakehead System. The Canadian Mainline is a common carrier pipeline system which transports various grades of oil and other liquid hydrocarbons within western Canada and from western Canada to the Canada/United States border near Gretna, Manitoba and Neche, North Dakota and from the United States/Canada border near Port Huron, Michigan and Sarnia, Ontario to eastern Canada and the northeastern United States. The Canadian Mainline includes six adjacent pipelines, with a combined design operating capacity of approximately 2.85 million bpd that connect with the Lakehead System at the Canada/United States border, as well as four crude oil pipelines and one refined products pipeline that deliver into eastern Canada and the northeastern United States. It also includes certain related pipelines and infrastructure, including decommissioned and deactivated pipelines. Enbridge has operated, and frequently expanded, the Canadian Mainline since 1949. Effective September 1, 2015, the closing date of the Canadian Restructuring Plan, Enbridge transferred the Canadian Mainline to the Fund Group –see Canadian Restructuring Plan. The Canadian Mainline assets and results are reported under the Sponsored Investments segment from the date of transfer. The Lakehead System is the portion of the mainline system in the United States that continues to be managed by Enbridge through its subsidiaries – see Sponsored Investments – Enbridge Energy Partners, L.P. and Enbridge Energy, Limited Partnership. Competitive Toll Settlement The CTS is the current framework governing tolls paid for products shipped on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis. The 10-year settlement was negotiated by representatives of Enbridge, the Canadian Association of Petroleum Producers and shippers on the Canadian Mainline. It was approved by the NEB on June 24, 2011 and took effect on July 1, 2011. The CTS provides for a Canadian Local Toll (CLT) for deliveries within western Canada, which is based on the 2011 Incentive Tolling Settlement toll, as well as an IJT for crude oil shipments originating in western Canada on the Canadian Mainline and delivered into the United States, via the Lakehead System, and into eastern Canada. These tolls are denominated in United States dollars. The IJT is designed to provide shippers on the mainline system with a stable and competitive long-term toll, thereby preserving and enhancing throughput on both the Canadian Mainline and the Lakehead System. The IJT and the CLT were both established at the time of implementation of the CTS and are adjusted annually, on July 1 of each year, at a rate equal to 75% of the Canada Gross Domestic Product at Market Price Index published by Statistics Canada. Certain events may trigger a renegotiation of the CTS by Enbridge or the shippers. These include (i) a regulatory change that results in cumulative capital expenditures for integrity work on the Canadian Mainline increasing by more than $100 million, or (ii) if the nine month average volume on the Canadian Mainline, ex-Gretna, Manitoba, falls below the minimum threshold volume (currently 1.35 million bpd). If a renegotiation of the CTS is triggered, Enbridge and the shippers will meet and use reasonable efforts to agree on how the CTS can be amended to accommodate the event. If Enbridge and the shippers are unable to agree on the manner in which the CTS is to be amended, then, absent an extension to the renegotiation period, the CTS will 50 Enbridge Inc. 2015 Annual Report
terminate and Enbridge will need to file a new toll application for the Canadian Mainline. Two years prior to the end of the term of the CTS, Enbridge and the shippers will establish a group for the purposes of negotiating a new settlement to replace the CTS once it expires. Although the CTS has a 10 year term, it does not require shippers to commit to certain volumes. Shippers nominate volumes on a monthly basis and Enbridge allocates capacity to maximize the efficiency of the Canadian Mainline. Local tolls for service on the Lakehead System are not affected by the CTS and continue to be established pursuant to the Lakehead System’s existing toll agreements. Under the terms of the IJT agreement between Enbridge and EEP, the Canadian Mainline’s share of the IJT toll relating to pipeline transportation of a batch from any western Canada receipt point to the United States border is equal to the IJT toll applicable to that batch’s United States delivery point less the Lakehead System’s local toll to that delivery point. This amount is referred to as the Canadian Mainline IJT Residual Benchmark Toll and is denominated in United States dollars. Results of Operations Canadian Mainline adjusted earnings for year ended December 31, 2015 are impacted by the effect of the Canadian Restructuring Plan. Prior to September 1, 2015, the closing date of the Canadian Restructuring Plan, Canadian Mainline results were reflected in Liquids Pipelines. Following the close of the Canadian Restructuring Plan on September 1, 2015, the results of Canadian Mainline are no longer reported in the Liquids Pipelines segment, but are captured in the results of the Fund Group which are reported within Sponsored Investments – see Sponsored Investments – The Fund Group. For further details on the Canadian Restructuring Plan refer to Canadian Restructuring Plan. Canadian Mainline adjusted earnings were $395 million for the eight month period ended August 31, 2015 compared with $500 million for the year ended December 31, 2014. Prior to the closing of the Canadian Restructuring Plan on September 1, 2015, Canadian Mainline adjusted earnings increased compared with the corresponding 2014 periods. The period-over-period increase reflected higher throughput from strong oil sands production combined with strong refinery demand in the midwest market partly due to a start-up of a midwest refinery’s conversion to heavy oil processing in the second quarter of 2014. Higher throughput in the third quarter of 2015 was also achieved from the expansion of the Company’s mainline system completed in July 2015 and through continued efforts by the Company to optimize capacity utilization and to enhance scheduling efficiency with shippers. Although throughput increased relative to the comparative periods in 2014, further throughput growth in 2015 was hindered by upstream plant maintenance in Alberta during the second and third quarters which impacted light volumes, and an unplanned shutdown of a midwest refinery that impacted the takeaway of heavy volumes in the third quarter. Other factors contributing to an increase in adjusted earnings were higher terminalling revenues and the impact of a stronger United States dollar as the IJT Benchmark Toll and its components are set in United States dollars. The majority of the Company’s foreign exchange risk on Canadian Mainline earnings is hedged; however, the average foreign exchange rate at which these revenues were hedged was higher during the eight month period ended August 31, 2015 compared with the same period in 2014. These trends continued into the month of September and in the fourth quarter of 2015, although the throughput impacts related to the upstream plant maintenance and shutdown of a midwest refinery noted above were alleviated towards the latter part of the fourth quarter of 2015. In addition, Canadian Mainline fourth quarter of 2015 adjusted earnings also reflected one month of revenues from Line 9B which was placed into service in December 2015. The Canadian Mainline adjusted earnings for the month of September and the fourth quarter of 2015 are reflected in the Fund Group, whereas adjusted earnings for the comparative 2014 periods were reflected in Liquids Pipelines. Partially offsetting the positive factors noted above for the eight month period ended August 31, 2015 was a lower average Canadian Mainline IJT Residual Benchmark Toll, although this impact lessened commencing the second quarter of 2015 as effective April 1, 2015, this toll increased by US$0.10 per barrel to US$1.63 per barrel. Changes in the Canadian Mainline IJT Residual Benchmark Toll are inversely related to the Lakehead System Toll, which was higher due to the recovery of incremental costs associated with EEP’s growth projects. Also mitigating the impact of a lower Canadian Mainline IJT Residual Benchmark Toll were new surcharges related to system expansions, including a surcharge for the Edmonton to Hardisty Expansion pipeline completed in April 2015. Other factors which negatively impacted adjusted earnings were higher power costs associated with higher throughput, higher depreciation expense due to an increased asset base and higher interest expense resulting from higher outstanding debt to support increased business activities. These trends also continued into the month of September and in the fourth quarter of 2015. Canadian Mainline adjusted earnings were $500 million for the year ended December 31, 2014 compared with $460 million for the year ended December 31, 2013. Adjusted earnings growth was primarily driven by higher throughput with several factors contributing to the increase including increased oil sands production, strong refinery demand in the midwest market partly due to a start-up of a midwest refinery’s conversion to heavy oil processing in the second quarter of 2014 and successful efforts by the Company to optimize capacity and throughput and to enhance scheduling efficiency with shippers. Other positive contributors to adjusted earnings included higher terminalling revenues, lower operating and administrative costs and lower income tax expense, which reflected current income taxes only and was lower due to higher available tax deductions. Partially offsetting these positive impacts in 2014 was a lower year-over-year average Canadian Mainline IJT Residual Benchmark Toll, with its impact especially prominent in the fourth quarter of 2014. In the fourth quarter of 2014, the Canadian Mainline IJT Residual Benchmark Toll was US$1.53 per barrel compared with US$1.80 per barrel in the equivalent period of 2013. The decrease in the toll was a key contributor to lower adjusted earnings in the fourth quarter of 2014 compared with the same period of 2013. Also negatively impacting adjusted earnings were higher power costs associated with incremental throughput as well as higher depreciation from an increased asset base. Finally, Canadian Mainline adjusted earnings for 2014 were impacted by the absence of revenues from Line 9B, which was idled in late 2013, pending its reversal and expansion which was subsequently completed in late 2015. Management’s Discussion & Analysis 51
Supplemental information on Canadian Mainline adjusted earnings for the years ended December 31, 2015, 2014 and 2013 is provided below. Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) 6 Revenues 1,837 1,465 1,434 Expenses 6 Operating and administrative 426 381 407 Power 224 160 122 Depreciation and amortization 295 270 244 945 811 773 892 654 661 Other income 3 11 3 Interest expense (201) (162) (162) 694 503 502 Income taxes (26) (3) (42) 668 500 460 1 Amounts attributable to the Fund Group within Sponsored Investments (273) –– 1 Adjusted earnings – Liquids Pipelines 395 500 460 2 Effective United States to Canadian dollar exchange rate 1.102 1.016 0.999 December 31, 2015 2014 2013 (United States dollars per barrel) 3 IJT Benchmark Toll $4.07 $4.02 $3.98 4 Lakehead System Local Toll $ 2.44 $2.49 $2.18 5 Canadian Mainline IJT Residual Benchmark Toll $1.63 $ 1.53 $1.80 1 Effective September 1, 2015, the results of Canadian Mainline are reflected in adjusted earnings from the Fund Group within the Sponsored Investments segment, whereas results prior to September 1, 2015, are reflected in Liquids Pipelines adjusted earnings. 2 Inclusive of realized gains and losses on foreign exchange derivative financial instruments. 3 The IJT Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil. Effective July 1, 2014, the IJT Benchmark Toll increased fromUS$3.98 to US$4.02 and increased to US$4.07 effective July 1, 2015. 4 The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective January 1, 2014, the Lakehead System Local Toll decreased fromUS$2.18 to US$2.17. In 2014, EEP delayed its annual April 1 tariff filing for its Lakehead Systemas it was in negotiations with the Canadian Association of Petroleum Producers concerning certain components of the tariff rate structure. The toll application was filed with the United States Federal Energy Regulatory Commission (FERC) on June 27, 2014, and effective August 1, 2014, the Lakehead System Local Toll increased fromUS$2.17 to US$2.49. Effective April 1, 2015, the Lakehead System Local Toll decreased fromUS$2.49 to US$2.39. Effective July 1, 2015, this toll increased to US$2.44. 5 The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll and the Lakehead System Local Toll. Effective January 1, 2014, this toll increased from US$1.80 to US$1.81. This toll increased to US$1.85 effective July 1, 2014 and subsequently decreased to US$1.53 effective August 1, 2014, coinciding with the revised Lakehead System Local Toll. Effective April 1, 2015, the Canadian Mainline IJT Residual Benchmark Toll increased to US$1.63. 6 In 2015, the Company commenced collecting, in its tolls, NEB mandated future abandonment costs from shippers. For the year ended December 31, 2015, approximately $38 million in revenue was recorded, but this amount was offset by a regulatory expense within operating and administrative expense. For further details, refer to Critical Accounting Estimates. 1 Throughput Volume Q1 Q2 Q3 Q4 Full Year 2015 2,210 2,073 2,212 2,243 2,185 2014 1,904 1,968 2,039 2,066 1,995 2013 1,783 1,604 1,736 1,827 1,737 1 Throughput, presented in thousands of bpd, represents mainline deliveries ex-Gretna, Manitoba, which is made up of United States and eastern Canada deliveries originating from western Canada. For the year ended December 31, 2015, the results of Canadian Mainline are reflected in Liquids Pipeline from January 1, 2015 to August 31, 2015. Effective September 1, 2015, the results of Canadian Mainline are reflected in the Fund Group within the Sponsored Investments segment. 52 Enbridge Inc. 2015 Annual Report
Canadian Mainline revenues include the portion of the system covered by the CTS as well as revenues from Lines 8 and 9 in eastern Canada. Lines 8 and 9 are currently tolled on a separate basis and comprise a relatively small proportion of total Canadian Mainline revenues. Line 9B was idled in late 2013 for reversal and expansion. The project was completed and the 300,000 bpd line was placed into service in December 2015 as part of the Company’s Eastern Access initiative – see Growth Projects – Commercially Secured Projects – Sponsored Investments – The Fund Group – Eastern Access. CTS revenues include transportation revenues, the largest component, as well as allowance oil and revenues from receipt and delivery charges. Transportation revenues include revenues for volumes delivered off the Canadian Mainline at Gretna, Manitoba and on to the Lakehead System, to which Canadian Mainline IJT residual tolls apply, and revenues for volumes delivered to other western Canada delivery points, to which the CLT applies. Despite the many factors that affect Canadian Mainline revenues, the primary determinants of those revenues will be throughput volume ex-Gretna, the United States dollar Canadian Mainline IJT Residual Benchmark Toll and the effective foreign exchange rate at which resultant revenues are converted into Canadian dollars. The Company currently utilizes derivative financial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues. The exact relationship between the primary determinants and actual Canadian Mainline revenues will vary somewhat from quarter to quarter but is expected to be relatively stable on average for a year, absent a systematic shift in receipt and delivery point mix or in crude oil type mix. The largest components of operating and administrative expense are employee related costs, pipeline integrity, repairs and maintenance, rents and leases and property taxes. Operating and administrative costs are relatively insensitive to throughput volumes. Power, the most significant variable operating cost, is subject to variations in operating conditions, including system configuration, pumping patterns and pressure requirements; however, the primary determinants of this cost are the power prices in various jurisdictions and throughput volume. The relationship of power consumption to throughput volume is expected to be roughly proportional over a moderate range of volumes. The Company currently utilizes derivative financial instruments to hedge power prices. Depreciation and amortization expense will adjust over time as a result of additions to property, plant and equipment due to new facilities, including integrity capital expenditures. Canadian Mainline income taxes reflect current income taxes only. Under the CTS, the Company retains the ability to recover deferred income taxes under an NEB order governing flow-through income tax treatment and, as such, an offsetting regulatory asset related to deferred income taxes is recognized as incurred. No other material regulatory assets or liabilities are recognized under the terms of the CTS. Regional Oil Sands System Regional Oil Sands System includes three long haul pipelines, the Athabasca Pipeline, Waupisoo Pipeline and Woodland Pipeline and two large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta and the Cheecham Terminal, located 70 kilometres (45 miles) south of Fort McMurray where the Waupisoo Pipeline initiates. Regional Oil Sands System also includes the Wood Buffalo Pipeline and Norealis Pipeline, each of which provides access for oil sands production from near Fort McMurray to the Cheecham Terminal. The recently completed Woodland Pipeline extension project further extended the Woodland Pipeline south from the Company’s Cheecham Terminal to its Edmonton Terminal. Regional Oil Sands System also includes a variety of other facilities such as the MacKay River, Christina Lake, Surmont, Long Lake and AOC laterals and related facilities. Regional Oil Sands System currently serves eight producing oil sands projects. Canadian Mainline – Average Deliveries (thousands of barrels per day) 2,185 1,995 1,646 1,737 1,554 11 12 13 14 15 Regional Oil Sands System Woodland Pipeline Norealis Athabasca Terminal Terminal Norealis Pipeline Wood Buffalo Pipeline AOC Hangingstone Cheecham Terminal Lateral Woodland Pipeline Extention Kirby Lake Terminal Sunday Waupisoo Pipeline Creek Terminal Edmonton Athabasca Pipeline Pi Hardisty ALBERTA Enbridge Mainline Management’s Discussion & Analysis 53
Effective September 1, 2015, the closing date of the Canadian Restructuring Plan, Enbridge transferred the Regional Oil Sands System to the Fund Group – see Canadian Restructuring Plan. The Regional Oil Sands System assets and results are reported under the Sponsored Investments segment from the date of transfer. The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic and heavy oil pipeline. Built in 1999, it links the Athabasca oil sands in the Fort McMurray region to the major Alberta pipeline hub at Hardisty, Alberta. The Athabasca Pipeline’s capacity is 570,000 bpd after completion of a pipeline expansion in December 2013. The Company has long-term take-or-pay and non take-or-pay agreements with multiple shippers on the Athabasca Pipeline. Revenues are recorded based on the contract terms negotiated with the major shippers, rather than the cash tolls collected. The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered service in 2008 and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline originates at the Cheecham Terminal and terminates at the major Alberta pipeline hub at Edmonton. The pipeline has a capacity of 550,000 bpd, depending on crude slate. The Company has long-term take-or-pay commitments with multiple shippers on the Waupisoo Pipeline who have collectively contracted for 80% to 90% of the capacity, subject to some short-term variability dependent on the timing of when certain shippers’ commitments expire and commence. Results of Operations Regional Oil Sands System adjusted earnings for the year ended December 31, 2015 were $108 million compared with $181 million for the year ended December 31, 2014. The decrease in adjusted earnings was primarily due to the transfer of the Regional Oil Sands System to the Fund Group, within the Sponsored Investments segment. Following the close of the Canadian Restructuring Plan on September 1, 2015, the results of Regional Oil Sands System are no longer reported in the Liquids Pipelines segment, but are captured in the financial results of the Fund Group within Sponsored Investments – see Sponsored Investments – The Fund Group. Prior to the closing of the Canadian Restructuring Plan on September 1, 2015, Regional Oil Sands System adjusted earnings were lower compared with the corresponding 2014 period and reflected a reduction in contracted volumes on the Athabasca Mainline, mitigated in part by higher uncommitted volumes on this pipeline. Higher depreciation expense from a larger asset base and higher interest expense also contributed to a decrease in period-over-period adjusted earnings. These negative effects were partially offset by higher earnings from assets placed into service in 2014 and 2015, including the Sunday Creek Terminal and Woodland Pipeline Extension projects that were placed into service in the third quarter of 2015 as well as Norealis Pipeline which was completed in April 2014. These trends continued into September as well as in the fourth quarter of 2015, with higher earnings from assets placed into service in the third quarter of 2015 partially offset by higher depreciation and interest expenses related to these assets, as well as the continuing impacts of the reduction in contracted volumes on the Athabasca Mainline. The Regional Oil Sands System adjusted earnings for the month of September and the fourth quarter of 2015 are reflected in the Fund Group, whereas adjusted earnings for the comparative 2014 periods were reflected in Liquids Pipelines. Regional Oil Sands System adjusted earnings for the year ended December 31, 2014 were $181 million compared with $170 million for the year ended December 31, 2013. Adjusted earnings growth in 2014 was primarily driven by contributions from the Norealis Pipeline which was completed in April 2014, higher throughput on the Athabasca Pipeline and higher capital expansion fee revenue from the Waupisoo Pipeline. Partially offsetting the increase in adjusted earnings were higher depreciation expense from a larger asset base and higher operating and administrative, interest and tax expenses from increased operational activities. Regional Oil Sands System – Average Deliveries (thousands of barrels per day) 759 703 533 414 334 11 12 13 14 15 54 Enbridge Inc. 2015 Annual Report
Line 37 Crude Oil Release On June 22, 2013, Enbridge reported a release of light synthetic crude oil on its Line 37 pipeline approximately two kilometres north of Enbridge’s Cheecham Terminal. Line 37 connects facilities in the Long Lake area to the Cheecham Terminal. The Company estimated the volume of the release at approximately 1,300 barrels, caused by unusually high water levels in the region that triggered ground movement on the right-of-way. The oil released from Line 37 was recovered and on July 11, 2013, Line 37 returned to service at reduced operating pressure. Normal operating pressure was restored on Line 37 on July 29, 2013 after finalization of geotechnical analysis. As a precaution, on June 22, 2013, the Company shut down the pipelines that share a corridor with Line 37, including the Athabasca, Waupisoo, Wood Buffalo and Woodland pipelines. Following extensive engineering and geotechnical analysis, all of the lines except Woodland Pipeline were returned to service by July 19, 2013. The Woodland Pipeline had been in the process of line-fill at the time of the shutdown; line-fill activities were completed in the third quarter of 2013. For the years ended December 31, 2015, 2014 and 2013, the Company’s earnings reflected remediation and long-term stabilization costs of approximately $5 million, $4 million and $56 million after-tax and before insurance recoveries, respectively, within Liquids Pipelines. Lost revenues associated with the shutdown of Line 37 and the pipelines sharing a corridor with Line 37 were minimal. At the time of the Line 37 crude oil release, Enbridge carried liability insurance for sudden and accidental pollution events, subject to a $10 million deductible. The integrity and stability costs associated with remediating the impact of the high water levels were precautionary in nature and not covered by insurance. Enbridge expects to record receivables for amounts claimed for recovery pursuant to its insurance policies during the period that it deems realization of the claim for recovery to be probable. Prior to the transfer of the Regional Oil Sands System to the Fund Group effective September 1, 2015, Enbridge recognized insurance recoveries of $9 million after-tax in connection with the Line 37 crude oil release within Liquids Pipelines, whereas in the fourth quarter of 2015, the Fund Group recognized insurance recoveries of $22 million ($13 million after-tax attributable to Enbridge) within Sponsored Investments. For the year ended December 31, 2014, insurance recoveries of $8 million after-tax were recognized in connection with the Line 37 crude oil release within Liquids Pipelines. On February 1, 2016, Enbridge was notified that the provincial government agency had completed and closed its investigation on this matter. Seaway and Flanagan South Pipelines Seaway and Flanagan South Pipelines include Enbridge’s 50% interest in Seaway Pipeline and whole ownership of Flanagan South. Seaway Pipeline In 2011, Enbridge acquired a 50% interest in the 1,078-kilometre (670-mile) Seaway Pipeline, including the 805-kilometre (500-mile), 30-inch diameter long-haul system between Cushing, Oklahoma and Freeport, Texas, as well as the Texas City Terminal and Distribution System which serves refineries in the Houston and Texas City areas. Seaway Pipeline also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast. The flow direction of Seaway Pipeline was reversed in May 2012, enabling it to transport crude from the oversupplied hub in Cushing, Oklahoma to the Gulf Coast. Further pump station additions and modifications were completed in January 2013, increasing capacity available to shippers from an initial 150,000 bpd to up to approximately 400,000 bpd, depending on crude oil slate. In late 2014, a second line was placed into service to more than double the existing capacity to 850,000 bpd. Seaway Pipeline also includes a 161-kilometre (100-mile) pipeline from the ECHO crude oil terminal in Houston, Texas to the Port Arthur/Beaumont, Texas refining centre. Flanagan South Pipeline Flanagan South is a 950-kilometre (590-mile), 36-inch diameter interstate crude oil pipeline that originates at the Company’s terminal at Flanagan, Illinois and terminates in Cushing, Oklahoma. Flanagan South and associated pumping stations were completed in the fourth quarter of 2014 and the majority of the pipeline parallels Spearhead Pipeline’s right-of-way. Flanagan South has an initial design capacity of approximately 600,000 bpd; however, in its initial years, it is not expected to operate at its full design capacity. Results of Operations Seaway and Flanagan South Pipelines adjusted earnings for the year ended December 31, 2015 were $103 million compared with adjusted earnings of $74 million for the year ended December 31, 2014. The increase in adjusted earnings reflected the effects of Flanagan South and Seaway Pipeline Twin commencing operations in late 2014. During the first half of 2015, as a result of Canadian Mainline apportionment, throughput on Seaway and Flanagan South Pipelines was lower than the throughput committed on these pipelines. However, this upstream apportionment was partially alleviated in the second half of 2015 through the expansion of the Company’s mainline system completed in July 2015. When committed shippers on Flanagan South are unable to fulfill their volume commitments due to apportionment, they are provided with temporary relief to make up those volumes during the course of their contracts or the apportioned volumes are added on to the end of the contract term. Seaway and Flanagan South Pipelines adjusted earnings for the year ended December 31, 2014 were $74 million compared with adjusted earnings of $48 million for the year ended December 31, 2013. Higher adjusted earnings reflected the incremental earnings associated with first oil received on Flanagan South and Seaway Pipeline Twin in December 2014. Also positively impacting adjusted earnings were higher average tolls on Seaway Pipeline. Partially offsetting the increased adjusted earnings were higher operating expense and financing costs from an increased asset base. Seaway Pipeline Regulatory Matter Seaway Pipeline filed an application for market-based rates in December 2011. In relation to the original market-based rate application, FERC issued its decision rejecting Seaway Pipeline’s application for market-based rates in February 2014. In the Seaway Pipeline order, FERC also announced a new methodology for determining whether a pipeline has market power and invited Seaway Pipeline to refile its market-based rate application consistent Management’s Discussion & Analysis 55
with the new policy. In December 2014, Seaway Pipeline filed a new market-based rate application. The FERC noticed the application in the Federal Register and in response several parties filed comments in opposition alleging that the application should be denied because Seaway Pipeline has market power in both its receipt and destination markets. On September 17, 2015, the FERC issued its decision setting the application for hearing. The case has been assigned to an ALJ, who held a scheduling conference on October 1, 2015, subsequent to which, evidence was filed on December 3, 2015. The scheduling order calls for a hearing to start on July 7, 2016 and an initial decision of the ALJ on December 1, 2016. Since the FERC had not issued a ruling on the market-based rate application, Seaway Pipeline filed for initial rates in order to have rates in effect by the in-service date. The uncommitted rate on Seaway Pipeline was challenged by several shippers. In September 2013, a decision from an ALJ was released finding that the committed and uncommitted rates on Seaway Pipeline should be reduced to reflect the ALJ’s findings on the various cost of service inputs. Seaway Pipeline filed a brief with the FERC on October 15, 2013, challenging the ALJ’s decision and asking for expedited ruling by the FERC on the committed rates. In February 2014, the FERC issued its decision upholding its policy to honour contracts and ordered the ALJ to revise her decision accordingly. On May 9, 2014, the ALJ issued an initial decision on remand reiterating her previous findings and did not change her decision. Briefings have concluded and the full record was sent to the FERC for its final decision, which was issued February 1, 2016. In its order, FERC again upholds the committed rates and reverses the ALJ’s holding that the committed rates should be reduced to cost-based levels. With respect to the uncommitted rates, FERC permits Seaway to include the full Enbridge purchase price (including goodwill) in rate base. FERC’s other cost-of-service rulings regarding the uncommitted rates are also largely favourable to Seaway. A compliance filing calculating revised rates is due March 17, 2016. Spearhead Pipeline Spearhead Pipeline is a long-haul pipeline that delivers crude oil from Flanagan, Illinois, a delivery point on the Lakehead System to Cushing, Oklahoma. The pipeline was originally placed into service in March 2006 and an expansion was completed in May 2009, increasing capacity from 125,000 bpd to 193,300 bpd. Initial committed shippers and expansion shippers currently account for more than 70% of the 193,300 bpd capacity on Spearhead Pipeline. Both the initial committed shippers and expansion shippers were required to enter into 10-year shipping commitments at negotiated rates that were offered during the open season process. In March 2015, the commitment agreements with the initial committed shippers were extended for an additional 10 years. The balance of the capacity is currently available to uncommitted shippers on a spot basis at FERC approved rates. Results of Operations Adjusted earnings for Spearhead Pipeline were $34 million for the year ended December 31, 2015 compared with $31 million for the year ended December 31, 2014. The increase in adjusted earnings reflected higher tariff rates and expiry of deficiency credits in the fourth quarter of 2015, as well as lower power costs. These positive factors were partially offset by lower throughput which was more prominent in the first nine months of 2015 due to upstream apportionment, refinery maintenance, unscheduled shutdown and power outages. Adjusted earnings for Spearhead Pipeline were $31 million for each of the years ended December 31, 2014 and 2013. 2014 adjusted earnings reflected a combination of higher throughput and tolls, as well as lower pipeline integrity expenditures that were more prominent in 2013. These positive factors were offset by incremental power costs associated with higher throughput and by higher administrative expense. Southern Lights Pipeline Southern Lights Pipeline is a fully-contracted single stream pipeline that ships diluent from the Manhattan Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. This 180,000 bpd 16/18/20-inch diameter pipeline was placed into service on July 1, 2010. Prior to the close of the Canadian Restructuring Plan, Southern Lights Canada was owned by SL Canada, an Alberta limited partnership. Southern Lights US is owned by Enbridge Pipelines (Southern Lights) L.L.C., a Delaware limited liability company. Both Southern Lights Canada and Southern Lights US receive tariff revenues under long-term contracts with committed shippers. Tariffs provide for recovery of all operating and debt financing costs plus an ROE of 10%. The Southern Lights Pipeline has assigned 10% of the capacity (18,000 bpd) for shippers to ship uncommitted volumes. As part of Enbridge’s sponsored vehicle strategy, on November 7, 2014, the Fund Group subscribed for and purchased the Class A Units of certain Enbridge subsidiaries that indirectly own the Canadian and Untied States segments of Southern Lights Pipeline (Southern Lights Class A units). The Southern Lights Class A units provide a defined cash flow stream to the Fund Group and represent the equity cash flows derived from the core rate base of Southern Lights Pipeline until June 30, 2040 – see Sponsored Investments – The Fund Group –The Fund Group Drop Down Transaction. Enbridge has guaranteed payment of the quarterly distributions that the Fund Group receives, except in circumstances of force majeure, certain regulatory actions and shipper defaults that remain unrecovered under the shipper contracts. The Fund Group has options to negotiate extensions for two additional 10-year terms beyond 2040 and to participate in equity returns from future expansions of Southern Lights Pipeline. 56 Enbridge Inc. 2015 Annual Report
In addition, as part of the Canadian Restructuring Plan, effective September 1, 2015, Enbridge transferred all Class B units of Southern Lights Canada to the Fund Group. Following the closing of the Transaction, the Fund Group holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights Canada. Enbridge continues to indirectly own all of the Class B Units of Southern Lights US. Results of Operations Southern Lights Pipeline adjusted earnings for the year ended December 31, 2015 were $11 million compared with $49 million for the year ended December 31, 2014. The majority of the economic benefit derived from Southern Lights Pipeline was reflected in earnings from the Fund Group following the Fund Group’s November 2014 subscription and purchase of Southern Lights Class A units. The Class A units provide a defined cash flow stream from Southern Lights Pipeline. In addition, adjusted earnings for 2015 also reflected the effects of the transfer of Southern Lights Canada’s Class B units as discussed above. Southern Lights Pipeline earnings were $49 million for each of the years ended December 31, 2014 and 2013, respectively. Earnings were comparable between the two fiscal years; however, due to offsetting factors. Higher recovery of negotiated depreciation rates in 2014 transportation tolls were offset by higher interest expense associated with the issuance of Class A units to the Fund Group. Feeder Pipelines and Other Feeder Pipelines and Other primarily includes the Company’s 85% interest in Olympic Pipe Line Company (Olympic), the largest refined products pipeline in the State of Washington, transporting approximately 290,000 bpd of gasoline, diesel and jet fuel. It also includes the NW System, which transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta, interests in a number of liquids pipelines in the United States, including the Toledo Pipeline, which connects with the EEP mainline at Stockbridge, Michigan, and the Company’s 75% joint venture interest in Eddystone Rail, a unit-train unloading facility and related local pipeline infrastructure near Philadelphia, Pennsylvania that delivers Bakken and other light sweet crude oil to Philadelphia area refineries, as well as business development costs related to Liquids Pipelines activities. Results of Operations Feeder Pipelines and Other adjusted earnings were $40 million for the year ended December 31, 2015 compared with $23 million for the year ended December 31, 2014. The increase in adjusted earnings was attributable to higher earnings from Eddystone Rail Project completed in April 2014, incremental earnings from certain storage agreements, higher tolls and throughput on Toledo Pipeline and contributions from Southern Access Extension which was placed into service in December 2015. Partially offsetting the increase in adjusted earnings were higher business development costs not eligible for capitalization in the first quarter of 2015, lower average tolls on Olympic Pipeline and higher property taxes relating to Toledo Pipeline in the third quarter of 2015. Feeder Pipelines and Other adjusted earnings were $23 million for the year ended December 31, 2014 compared with $12 million for the year ended December 31, 2013. The increase in adjusted earnings in Feeder Pipelines and Other reflected higher tolls and throughput on the Toledo Pipeline, incremental earnings from Eddystone completed in April 2014, higher tankage revenues and lower business development costs not eligible for capitalization. Partially offsetting the increase in adjusted earnings were lower average tolls on Olympic. Business Risks The risks identified below are specific to the Liquids Pipelines business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments –General Business Risks. Asset Utilization Enbridge is exposed to throughput risk under the CTS on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets. A decrease in volumes transported can directly and adversely affect revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of Enbridge’s assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions outside of Enbridge’s control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on Enbridge’s pipelines. However, the long-term outlook for Canadian crude oil production indicates a growing source of potential supply of crude oil. Under certain contracts, committed shippers are provided with relief from their take-or-pay payment obligations to the extent such shippers are unable to ship committed volumes on a pipeline solely as a result of Canadian Mainline apportionment. Enbridge seeks to mitigate utilization risks within its control. The market access expansion initiatives, which have had components placed into service over the past several years, and those currently under development have and are expected to further reduce capacity bottlenecks and enhance access to markets for customers. The Company also seeks to optimize capacity and throughput on its existing assets by working with the shipper community to enhance scheduling efficiency and communications, as well as makes continuous improvements to scheduling models and timelines to maximize throughput. Further to the day-to-day improvements sought by the Company, in 2014, Enbridge and EEP announced the $7.5 billion L3R Program. This project will not increase the overall capacity of the mainline system, but upon completion it will support the safety and operational reliability of the overall system and enhance the flexibility on the mainline system allowing the Company to further optimize throughput. Throughput risk is partially mitigated by provisions in the CTS agreement, which allow Enbridge to adjust the applicable L3R Program surcharge if volumes fall below defined thresholds or to negotiate an amendment to the agreement in the event certain minimum threshold volumes are not met. Management’s Discussion & Analysis 57
Operational and Economic Regulation Operational regulation risks relate to failing to comply with applicable operational rules and regulations from government organizations and could result in fines or operating restrictions or an overall increase in operating and compliance costs. Regulatory scrutiny over the integrity of liquids pipeline assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on the Company’s future earnings and the cost related to the construction of new projects. The Company believes operational regulation risk is mitigated by active monitoring and consulting on potential regulatory requirement changes with the respective regulators or through industry associations. The Company also develops robust response plans to regulatory changes or enforcement actions. While the Company believes the safe and reliable operation of its assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators to make unilateral decisions that could have a financial impact on the Company. The Company’s liquids pipelines also face economic regulatory risk. Broadly defined, economic regulation risk is the risk regulators or other government entities change or reject proposed or existing commercial arrangements including permits and regulatory approvals for new projects. The Canadian Mainline and other liquids pipelines are subject to the actions of various regulators, including the NEB and the FERC, with respect to the tariffs and tolls of those operations. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on the Company’s revenues and earnings. Delays in regulatory approvals could result in cost escalations and construction delays, which also negatively impact the Company’s operations. The Company believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of the Company’s liquids pipeline assets. The Company also involves its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations as well as in the establishment of tariffs and tolls on new and existing pipelines. However, despite the efforts of the Company to mitigate economic regulation risk, there remains a risk that a regulator could overturn long-term agreements between the Company and shippers or deny the approval and permits for new projects. Competition Competition may result in a reduction in demand for the Company’s services, fewer project opportunities or assumption of risk that results in weaker or more volatile financial performance than expected. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. Other competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada and the United States represent competition to the Company’s liquids pipelines network. Competition also arises from proposed pipelines that seek to access markets currently served by the Company’s liquids pipelines, such as proposed projects to the Gulf Coast or eastern markets. Competition also exists from proposed projects enhancing infrastructure in the Alberta regional oil sands market. Additionally, volatile crude price differentials and insufficient pipeline capacity on either Enbridge or other competitor pipelines can make transportation of crude oil by rail competitive, particularly to markets not currently serviced by pipelines. The Company believes that its liquids pipelines continue to provide attractive options to producers in the WCSB due to its competitive tolls and flexibility through its multiple delivery and storage points. Enbridge’s current complement of growth projects to expand market access and to enhance capacity on the Company’s pipeline system combined with the Company’s commitment to project execution is expected to further provide shippers reliable and long-term competitive solutions for oil transportation. The Company’s existing right-of-way for the Canadian Mainline also provides a competitive advantage as it can be difficult and costly to obtain rights of way for new pipelines traversing new areas. The Company also employs long-term agreements with shippers, which also mitigate competition risk by ensuring consistent supply to the Company’s liquids pipelines network. Foreign Exchange and Interest Rate Risk The CTS agreement for the Canadian Mainline exposes the Company to risks related to movements in foreign exchange rates and interest rates. Foreign exchange risk arises as the Company’s IJT under the CTS is charged in United States dollars. These risks have been substantially managed through the Company’s hedging program by using financial contracts to fix the prices of United States dollars and interest rates. Certain of these financial contracts do not qualify for cash flow hedge accounting and, therefore, the Company’s earnings are exposed to associated changes in the mark-to-market value of these contracts. 58 Enbridge Inc. 2015 Annual Report
Gas Distribution Earnings 2015 2014 2013 (millions of Canadian dollars) Enbridge Gas Distribution Inc. (EGD) 180 158 156 Other Gas Distribution and Storage 30 19 20 Adjusted earnings 210 177 176 EGD – colder than normal weather 11 36 9 EGD – changes in unrealized derivative fair value loss (3) –– EGD – employe severance cost adjustment 4 –– EGD – gas transportation costs out-of-period adjustment – –(56) Earnings attributable to common shareholders 222 213 129 Adjusted earnings from Gas Distribution were $210 million for the year ended December 31, 2015 compared with $177 million for the year end December 31, 2014 and $176 million for the year ended December 31, 2013. EGD 2015 and 2014 results reflected rates as established under EGD’s customized IR Plan. EGD generated higher adjusted earnings in 2015 primarily due to an increase in distribution charges that resulted from an increased asset base, as well as customer growth. In 2015, adjusted earnings from Other Gas Distribution and Storage reflected the absence of a contract loss that Enbridge Gas New Brunswick Inc. (EGNB) incurred in 2014. Additional details on items impacting Gas Distribution earnings include: EGD earnings for 2013 reflected an out-of-period correction to gas transportation • costs that had previously been deferred. Enbridge Gas Distribution Inc. EGD is Canada’s largest natural gas distribution company and has been in operation for more than 160 years. It serves over two million customers in central and eastern Ontario and parts of northern New York State. EGD’s utility operations are regulated by the OEB and the New York State Public Service Commission. Incentive Rate Plan EGD’s 2015 and 2014 rates were set in accordance with parameters established by the customized IR Plan. The customized IR Plan was approved in 2014 by the OEB, with modifications, for 2014 through 2018, inclusive of the requested capital investment amounts and an incentive mechanism providing the opportunity to earn above the allowed ROE. The customized IR Plan provides the methodology for establishing rates for the distribution of natural gas for a five-year period from 2014 through 2018. Within annual rate proceedings for 2015 through 2018, the customized IR Plan requires allowed revenues and corresponding rates to be updated annually for select items including the rate of return to be earned on the equity component of its rate base. The OEB also approved the adoption of a new approach for determining net salvage percentages to be included within EGD’s approved depreciation rates, as compared with the traditional approach previously employed. The new approach results in lower net salvage percentages for EGD, and therefore lowers depreciation rates and future removal and site restoration reserves. For the year ended December 31, 2015, EGD’s rates were set according to the OEB approved settlement agreement (April 2015) and the final rate order (May 2015). The rates approved as part of the 2015 rate application represented the second year of the Company’s customized IR Plan. For the year ended December 31, 2014, EGD’s rates were set by the OEB’s July 2014 decision, and subsequent August 2014 decision and rate order in the Company’s customized IR application. Gas Distribution Earnings (millions of Canadian dollars) 213 222 207 210 173 176 176 177 129 (88) 11 12 13 14 15 ? GAAP Earnings ? Adjusted Earnings Management’s Discussion & Analysis 59
In order to align the interest of customers with the Company’s shareholders, the customized IR Plan includes an earnings sharing mechanism, whereby any return over the allowed rate of return for a given year under the customized IR Plan is to be shared equally with customers. For the years ended December 31, 2015 and 2014, EGD recognized $7 million and $12 million, respectively, as a return of revenues to customers in relation to the earnings sharing mechanism. EGD’s 2013 rates were set pursuant to an OEB approved settlement agreement and decision (the 2013 Settlement) related to its 2013 cost of service rate application. The 2013 Settlement retained the previous deemed equity level but provided for an increase in the allowed ROE. The 2013 Settlement further retained the flow-through nature of the cost of natural gas supply and several other cost categories. There was no earnings sharing mechanism under the 2013 Settlement. The 2013 Settlement allowed EGD to recognize revenue and a corresponding regulatory asset relating to other postretirement benefit obligations (OPEB) as it established the right to recover previous OPEB costs of approximately $89 million ($63 million after-tax) over a 20-year time period commencing in 2013. The 2013 Settlement further provided for OPEB and pension costs, determined on an accrual basis, to be recovered in rates. Results of Operations EGD adjusted earnings for the year ended December 31, 2015 were $180 million compared with $158 million for the year ended December 31, 2014. While both years reflected rates as established under the customized IR Plan, the higher adjusted earnings in 2015 were primarily attributable to an increase in distribution charges that resulted from an increased asset base, as well as customer growth during the year in excess of expectations embedded in rates. EGD adjusted earnings for the year ended December 31, 2014 were $158 million compared with $156 million for the year ended December 31, 2013. The slight increase in EGD year-over-year adjusted earnings reflected customer growth, lower employee related and other costs and the impact of the approved customized IR Plan. The customized IR Plan included a new approach for determining depreciation and future removal and site restoration reserves, which resulted in a lower depreciation expense for the year ended December 31, 2014. These positive effects were partially offset by reduced rates and the resumption of the earnings sharing mechanism under the customized IR Plan, as well as lower shared savings mechanism revenues. Enbridge Gas Distribution – Number of Active Customers (thousands) 98 9 12 7 032 065 0 2, 2, 99 2, 2, 1, 11 12 13 14 15 Other Gas Distribution and Storage Other Gas Distribution includes natural gas distribution utility operations in Quebec and New Brunswick, the most significant being EGNB which is wholly-owned and operated by the Company. EGNB operates the natural gas distribution franchise in the province of New Brunswick, has approximately 12,000 customers and is regulated by the New Brunswick Energy and Utilities Board (EUB). Results of Operations Other Gas Distribution and Storage earnings were $30 million for the year ended December 31, 2015 compared with $19 million for the year ended December 31, 2014. The increase in earnings reflected the absence of a loss that EGNB incurred in 2014 under a contract to sell natural gas to the province of New Brunswick. Due to an abnormally cold winter in the first quarter of 2014, costs associated with the fulfilment of the contract were higher than the revenues received. Excluding the impact of the above noted contract which expired in October 2014, EGNB adjusted earnings increased slightly in 2015 due to higher distribution revenues. Other Gas Distribution and Storage earnings were $19 million for the year ended December 31, 2014 compared with $20 million for the year ended December 31, 2013. Lower earnings included a loss from EGNB related to the natural gas sale contract with the province of New Brunswick as noted above. Higher distribution volumes and higher rates that became effective in May 2014 partially offset the decreased earnings in EGNB. Gas Distribution CANADA Enbridge Gas New Brunswick Gaz Métro Quebec City St. John Gazifère Montreal Ottawa Toronto St. Lawrence Gas Enbridge Gas Sarnia Distribution UNITED STATES OF AMERICA 60 Enbridge Inc. 2015 Annual Report
Enbridge Gas New Brunswick Inc. – Regulatory Matters In April 2012, the Company commenced an action against the Government of New Brunswick in the New Brunswick courts, seeking damages for breach of contract. The action seeks recovery of damages alleged to have arisen due to various breaches of the General Franchise Agreement with EGNB, under which EGNB operates in the province. In May 2012, the Company also commenced a separate application to the New Brunswick courts to challenge elements of the Government’s rates and tariffs regulation, as it then existed. Ultimately, the Company was successful in defeating the part of the rates and tariffs regulation that capped rates according to a maximum revenue-to-cost ratio. Consequently, EGNB has been able to recover substantially all of its revenue requirement since August 2013, when the successful result of this legal challenge was first implemented into rates. On February 4, 2014, EGNB commenced second action against the Government of New Brunswick in the New Brunswick courts. The action seeks damages for improper extinguishment of a deferred regulatory asset that was eliminated from EGNB’s Consolidated Statements of Financial Position in 2012, due to legislative and regulatory changes enacted by the Government of New Brunswick in that year. There is no assurance that either of the two actions presently maintained by EGNB against the Province of New Brunswick will be successful or will result in any recovery. Business Risks The risks identified below are specific to Gas Distribution business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. Economic Regulation The utility operations of Gas Distribution are regulated by the OEB and EUB among others. Regulators’ future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which Gas Distribution operates. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position, or that would have been recorded on the Consolidated Statements of Financial Position in absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded. The Company seeks to mitigate economic regulation risk by maintaining regular and transparent communication with regulators and intervenors on rate negotiations. The terms of rate negotiations are also reviewed by the Company’s legal, regulatory and finance teams. The approval of the five-year customized IR Plan in 2014 also provides a level of stability by having a longer-term agreement with the OEB which allows EGD to recover its expected capital investments under the agreement, as well as an opportunity to earn above the OEB allowed ROE. Under the customized IR Plan, EGD is permitted to recover, with OEB approval, certain costs that were beyond management control, but that were necessary for the maintenance of its services. The customized IR Plan also includes a mechanism to reassess the customized IR Plan and return to cost of service if there are significant and unanticipated developments that threaten the sustainability of the customized IR Plan. The above noted terms set out in the settlement agreement mitigate the Company’s risk to factors beyond management’s control. Natural Gas Cost Risk EGD does not profit from the sale of natural gas nor is it at risk for the difference between the actual cost of natural gas purchased and the price approved by the OEB for inclusion in distribution rates. This difference is deferred as a receivable from or payable to customers until the OEB approves its refund or collection. EGD monitors the balance and its potential impact on customers and may request interim rate relief to recover or refund the natural gas cost differential. While the cost of natural gas does not impact EGD’s earnings, it does affect the amount of EGD’s investment in gas in storage. The OEB also determines the timing of payment or collection from customers which can have an impact on EGD’s working capital during the period in which costs are expected to be recovered. EGNB is also subject to natural gas cost risk as increases in natural gas prices that cannot be fully recovered from customers in the current period can negatively impact cash flow. Increased commodity costs will also impact the amount that may be charged in future distribution rates due to EGNB’s regulatory structure. Volume Risk Since customers are billed on a volumetric basis, EGD’s ability to collect its total revenue requirement (the cost of providing service) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a significant driver of delivery volumes, given that a significant portion of EGD’s customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continue to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption. Sales and transportation of gas for customers in the residential and small commercial sectors account for approximately 80% of total distribution volume. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Customer additions from all market sectors are important as continued expansion adds to the total consumption of natural gas. Even in those circumstances where EGD attains its total forecast distribution volume, it may not earn its expected ROE due to other forecast variables, such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector. EGNB is also subject to volume risk as the impact of weather conditions on demand for natural gas could result in earnings fluctuations. Management’s Discussion & Analysis 61
Gas Pipelines, Processing and Energy Services Earnings 2015 2014 2013 (millions of Canadian dollars) Aux Sable (7) 28 49 Energy Services 42 35 75 Alliance Pipeline US – 41 43 Vector Pipeline 16 15 22 Canadian Midstream 41 23 12 Enbridge Offshore Pipelines (Offshore) (2) (2) (2) Other (1) (4) 4 Adjusted earnings 89 136 203 Aux Sable – accrual for commercial arrangements (19) –– Energy Services – changes in unrealized derivative fair value gains/(loss) 152 424 (206) Canadian Midstream – impact of tax rate changes (3) –– Offshore – gain on sale of non-core assets 4 57 – Other – changes in unrealized derivative fair value loss – –(61) Other – impact of tax rate changes (5) –– Earnings/(loss) attributable to common shareholders 218 617 (64) Adjusted earnings from Gas Pipelines, Processing and Energy Services were $89 million for the year ended December 31, 2015 compared with $136 million for the year ended December 31, 2014 and $203 million for the year ended December 31, 2013. Unfavourable market conditions in Aux Sable and absence of earnings from the United States portion of the Alliance Pipeline (Alliance Pipeline US) which was transferred to the Fund Group in November 2014 contributed to the lower adjusted earnings in 2015. Lower fractionation margins and the loss of a producer processing contract at the Palermo Conditioning Plant have contributed to lower Aux Sable earnings over the past two years. Aux Sable 2015 results were also negatively impacted by costs associated with feedstock supply. Partially offsetting the decrease in 2015 were higher take-or-pay fees on Canadian Midstream assets and higher contributions from Energy Services. Energy Services benefitted from more favourable tank management opportunities resulting from strong refinery demand for blended crude oil feedstock, partially offset by the effects of less favourable conditions which persisted over the past two years in certain markets accessed by committed transportation capacity involving unrecovered demand charges. Additional details on items impacting Gas Pipelines, Processing and Energy Services earnings/(loss) include: Energy Services earnings/(loss) for each period reflected changes in unrealized fair value gains and losses related to the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and the revaluation of inventory. Energy Services adjusted earnings for 2014 excluded a realized loss of $117 million incurred to close out certain forward derivative financial contracts intended to hedge the value of committed physical transportation capacity in certain markets accessed by Energy Services, but were determined to be no longer effective in doing so. Energy Services adjusted earnings for 2013 excluded a realized loss of $58 million incurred to close out derivative contracts intended to hedge forecasted Energy Services transactions which did not occur. 62 Enbridge Inc. 2015 Annual Report
Other loss for 2015 included the impact of a corporate tax rate • change in the province of Alberta on opening deferred income tax balances. Other loss for 2013 reflected changes in unrealized fair value • loss on the long-term power price derivative contracts acquired to hedge expected revenues and cash flows from Blackspring Ridge wind project. Aux Sable Enbridge owns a 42.7% interest in Aux Sable US and Aux Sable Midstream US, and a 50% interest in Aux Sable Canada (together, Aux Sable). Aux Sable US owns and operates a NGL extraction and fractionation plant at Channahon, Illinois, outside Chicago, near the terminus of Alliance Pipeline. The plant extracts NGL from the liquids-rich natural gas transported on Alliance Pipeline as necessary for Alliance Pipeline to meet gas quality specifications of downstream transmission and distribution companies and to take advantage of positive fractionation spreads. Aux Sable US sells its NGL production to a single counterparty under a long-term contract. Aux Sable receives a fixed annual fee and a share of any net margin generated from the business in excess of specified natural gas processing margin thresholds (the upside sharing mechanism). In addition, Aux Sable is compensated for all operating and maintenance costs, and subject to certain limits, costs incurred to source feedstock supply and capital costs associated with its facilities. The counterparty supplies all make-up gas and fuel gas requirements of the Aux Sable plant. The contract is for an initial term of 20 years, expiring March 31, 2026, and may be extended by mutual agreement for 10-year terms. Aux Sable also owns facilities upstream of Alliance Pipeline that deliver liquids-rich gas volumes into the pipeline for further processing at the Aux Sable plant. These facilities include the Palermo Conditioning Plant and the Prairie Rose Pipeline in the Bakken area of North Dakota, owned and operated by Aux Sable Midstream US; as well as Aux Sable Canada’s interests in the Montney area of British Columbia comprising Septimus Pipeline and a 22% interest it acquired effective October 1, 2015 in the Septimus and Wilder Gas Plants in exchange for its previously held 50% ownership interest in the Septimus Plant. Aux Sable Canada has contracted capacity on the Septimus Pipeline and the Septimus and Wilder Gas Plants to a producer under a 10-year take-or-pay contract which provides for a return on and of invested capital. Actual operating costs are recovered from the producer. In 2015, the majority of capacity at the Palermo Gas Plant and on the Prairie Rose Pipeline was contracted to producers under take-or-pay contracts. Several producers’ contract commitments will decline over the next few years while certain producer contract commitments will continue through 2020 under long-term take-or-pay contracts or with life-of-lease reserve dedication. Additional revenues are earned by Aux Sable based on a sharing of available NGL margin with producers. In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the United States Environmental Protection Agency (EPA) for alleged violations of the Clean Air Act related to the Leak Detection and Repair program, and related provisions of the Clean Air Act permit for Aux Sable’s Channahon, Illinois facility. As part of the ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believes to be an exceedance of currently permitted limits for Volatile Organic Material. Aux Sable received a second NFOV from the EPA in April 2015 in connection with this potential exceedance. Aux Sable is engaged in discussions with the EPA to evaluate the potential impact and ultimate resolution of these issues. Initial settlement proposal with the EPA confirms the amount will not be material. Results of Operations Aux Sable reported an adjusted loss of $7 million for the year ended December 31, 2015 compared with adjusted earnings of $28 million for the year ended December 31, 2014. Lower fractionation margins resulting from a weaker commodity price environment, absence of contributions from the upside sharing mechanism, costs associated with feedstock supply and the loss of a producer processing contract at the Palermo Conditioning Plant were the main drivers behind the year-over-year decreases in adjusted earnings. Aux Sable adjusted earnings for the year ended December 31, 2014 were $28 million compared with adjusted earnings of $49 million for the year ended December 31, 2013. Aux Sable earnings reflected lower fractionation margins which decreased contributions from the upside sharing mechanism, partially offset by an increase in propane volumes produced at the Channahon Plant. Lower volumes at upstream processing plants and higher administrative expense also had a negative impact on Aux Sable earnings. Aux Sable Feedstock Supply Aux Sable secures NGL feedstock for its Channahon Plant through Rich Gas Premium (RGP) contracts with producers, with varying terms ranging up to a maximum of seven years. RGP contracts provide for producers and Aux Sable to share in the value of the liquids-rich natural gas (both residual dry gas and extracted NGL) transported on the Alliance Pipeline. RGP contract volumes increased as of December 1, 2015, following the termination of essentially all of Alliance Pipeline’s initial long-term transportation contracts. Effective December 1, 2015, producers have contracted for firm transportation service under Alliance Pipeline’s New Service Framework, and either transport volumes to Aux Sable’s Channahon Plant or to the new Alliance Trading Point (ATP), notionally located on the Canadian portion of the Alliance Pipeline system. Aux Sable purchases RGP gas volumes delivered to ATP and through corresponding gas sales contracts, assignments or other arrangements with counterparties, Aux Sable facilitates the transport of purchased gas to the Channahon Plant. For further details on Alliance Pipeline Recontracting, refer to Sponsored Investments – The Fund Group – Alliance Pipeline Recontracting. Business Risks The risks identified below are specific to Aux Sable. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks. Commodity Price Risk Aux Sable’s NGL margin earned through the upside sharing mechanism is subject to commodity price risk arising from the price differential between the cost of natural gas and the value achieved from the sale of extracted NGL after the fractionation process. Management’s Discussion & Analysis 63
Aux Sable is also subject to the value of natural gas on the Alliance Pipeline supplied by certain of its RGP producers. To mitigate this natural gas supply risk, Aux Sable has entered into a variety of contracts with counterparties. Commodity price risk created from Aux Sable’s RGP contracts and through the upside sharing mechanism is closely monitored and must comply with its formal risk management policies that are consistent with the Company’s risk management practices. These risks may be mitigated by Aux Sable or through the Company’s risk management activities. Asset Utilization A decrease in gas volumes or a decrease in the NGL content of the gas stream delivered by Alliance Pipeline to the Aux Sable plant can directly and adversely affect margins earned. Aux Sable is well-positioned to offer RGP contracts, when necessary, to producers within the liquids-rich Montney, Duvernay and Bakken plays that are located in close proximity to Alliance Pipeline to mitigate these risks. Energy Services Energy Services provides energy supply and marketing services to North American refiners, producers and other customers. Crude oil and NGL marketing services are provided by Tidal Energy. This business transacts at many North American market hubs and provides its customers with various services, including transportation, storage, supply management, hedging programs and product exchanges. Tidal Energy is primarily a physical barrel marketing company focused on capturing value from quality, time and location differentials when opportunities arise. To execute these strategies, Energy Services may lease storage or rail cars, as well as hold nomination or contractual rights on both third party and Enbridge-owned pipelines and storage facilities. Tidal Energy also provides natural gas marketing services, including marketing natural gas to optimize commitments on certain natural gas pipelines. Additionally, Tidal Energy provides natural gas supply, transportation, balancing and storage for third parties, leveraging its natural gas marketing expertise and access to transportation capacity. Any commodity price exposure created from Tidal Energy’s physical business is closely monitored and must comply with the Company’s formal risk management policies. To the extent transportation costs and other fees exceed the basis (location) differential, earnings will be negatively affected. Results of Operations Energy Services adjusted earnings were $42 million for the year ended December 31, 2015 compared with adjusted earnings of $35 million for the year ended December 31, 2014. Higher earnings in 2015 reflected strong refinery demand for blended crude oil feedstock leading to more favourable tank management opportunities in the first half of 2015. Also favourably impacting year-over-year adjusted earnings was the absence of losses realized in the first quarter of 2014 on certain financial contracts as discussed below. The favourable tank management opportunities experienced in the first half of 2015 eroded in the second half of the year due to a reduction in refinery demand for blended crude oil feedstock and an increase in offshore crude supply in the Gulf Coast. The lack of favourable tank management opportunities together with the effects of less favourable conditions in certain markets accessed by committed transportation capacity involving unrecovered demand charges, resulted in an adjusted loss in the fourth quarter of 2015. Adjusted earnings from Energy Services are dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods. Energy Services adjusted earnings were $35 million for the year ended December 31, 2014 compared with $75 million for the year ended December 31, 2013. Adjusted earnings decreased in 2014 compared with a very strong 2013 due to narrowing location spreads and less favourable conditions in certain markets accessed by committed transportation capacity, combined with associated unrecovered demand charges. Additionally, the 2014 adjusted earnings reflected losses realized in the first quarter of 2014 on certain financial contracts intended to hedge the value of committed transportation capacity, but which were not effective in doing so. During the second and fourth quarters of 2014, the Company closed out a forward component of these derivative contracts which had been determined to be no longer effective. Partially offsetting the decrease in adjusted earnings in 2014 were more favourable conditions in certain markets in the fourth quarter of 2014 that gave rise to wider location and crude grade differentials and enabled Energy Services to capture more profitable margin and tank management arbitrage opportunities. Due in large part to the continued positive effects of these arbitrage opportunities, Energy Services 2014 fourth quarter adjusted earnings increased compared with the equivalent 2013 period which helped to partially offset the decrease in adjusted earnings experienced during the first nine months of the year. Also positively contributing to adjusted earnings were favourable natural gas location differentials caused by abnormal winter weather conditions during the first quarter of 2014. Business Risks The risks identified below are specific to Energy Services. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks. Commodity Price Risk Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Volatility in commodity prices and changing marketing conditions could limit margin opportunities. Furthermore, commodity prices could have negative earnings impacts if the cost of the commodity is greater than resale prices achieved by the Company. Energy Services activities are conducted in compliance with and under the oversight of the Company’s formal risk management policies, including the implementation of hedging programs to manage exposure to changes in commodity prices, inclusive of exposures inherent within forecasted transactions. 64 Enbridge Inc. 2015 Annual Report
Competition Energy Services earnings are generated from arbitrage opportunities which, by their nature, can be replicated by other competitors. An increase in market participants entering into similar arbitrage transactions could have an impact on the Company’s earnings. The Company’s efforts to mitigate competition risk includes diversification of its marketing business by trading at the majority of major hubs in North America and establishing long-term relationships with clients. Alliance Pipeline US In November 2014, Enbridge’s 50% ownership of the Alliance Pipeline US was transferred to the Fund Group with earnings contributions from Alliance Pipeline US prospectively reflected within the Sponsored Investments section effective November 7, 2014. Refer to Sponsored Investments – The Fund Group – Drop Down Transaction for details of the transfer. Effective November 7, 2014, the Fund Group owns 50% of Alliance Pipeline US along with its previous 50% ownership of the Canadian portion of the Alliance Pipeline (Alliance Pipeline Canada). For the Alliance Pipeline US asset overview, refer to Sponsored Investments – The Fund Group – Alliance Pipeline. For business risks specific to the Alliance Pipeline refer to Sponsored Investments – The Fund Group – Business Risks – Alliance Pipeline. Results of Operations The absence of Alliance Pipeline US earnings for the year ended December 31, 2015 reflected the transfer of Alliance Pipeline US to the Fund Group in November 2014. Alliance Pipeline US earnings were $41 million for the year ended December 31, 2014 compared with earnings of $43 million for the year ended December 31, 2013. The decrease in Alliance Pipeline US earnings reflected the impact of the transfer of Alliance Pipeline US to the Fund Group in November 2014 and the corresponding absence of earnings. Prior to November 7, 2014, the date of the transfer, Alliance Pipeline US earnings increased compared with the equivalent 2013 period and reflected an increase in depreciation expense recovered in tolls, as well as earnings from the Tioga Lateral pipeline which was placed into service in September 2013. Vector Pipeline Vector, which includes both the Canadian and United States portions of the pipeline system, consists of 560 kilometres (348 miles) of mainline natural gas transmission pipeline between the Chicago, Illinois hub and a storage complex at Dawn, Ontario. Vector’s primary sources of supply are through interconnections with Alliance Pipeline, Northern Border Pipeline and Guardian Pipeline in Joliet, Illinois. Vector has the capacity to deliver a nominal 1.3 billion cubic feet per day (bcf/d) and in 2015 it operated at or near capacity. The Company provides operating services to and holds a 60% joint venture interest in Vector.Results of Operations Vector earnings of $16 million for the year ended December 31, 2015 were comparable with earnings of $15 million for the year ended December 31, 2014. The positive effects of lower operating expenses and lower interest costs in 2015 due to debt repayment were offset by lower year-over-year transportation revenues as unusually high demand for natural gas transport was experienced in 2014 as discussed below. Vector earnings were $15 million for the year ended December 31, 2014 compared with earnings of $22 million for the year ended December 31, 2013. The year-over-year decrease in Vector earnings reflected lower depreciation expense recognized in tolls, partially offset by higher revenues due to increased demand for natural gas during abnormal winter weather conditions experienced in the first quarter of 2014. Transportation Contracts Vector’s total long haul capacity was 84% contracted under firm service agreements at December 31, 2015. Approximately 27% of long haul capacity is through firm negotiated rate transportation contracts with shippers and approved by the FERC, while the remaining firm service contracts are sold at market rates. In December 2015, shippers under negotiated rate transportation contracts which represent 20% of the system’s long haul capacity elected to extend their commitments through December 1, 2019 and preserve the option to extend their contracts on an annual basis. Vector is entitled to additional compensation from negotiated rate transportation shippers that terminate their contracts prior to the November 30, 2020 expiry date. In late 2014 and early 2015, Vector signed precedent agreements with both the proposed NEXUS Pipeline and Energy Transfer Partners L.P.’s Rover Pipeline project, to provide transportation service to the Dawn natural gas market hub. Both projects are in the development stage and are subject to FERC approval. These pipeline projects are proposed to enter service during the second half of 2017. Transportation service on Vector is provided through a number of different forms of service agreements, including Firm Transportation Service, Interruptible Transportation Service and Backhaul Service. Vector is an interstate natural gas pipeline with FERC and NEB approved tariffs that establish the rates, terms and conditions governing its service to customers. On the United States portion of Vector, maximum tariff rates are determined using a cost of service methodology and maximum tariff changes may only be implemented upon approval by the FERC. For 2015, the FERC-approved maximum tariff rates included an underlying weighted average after-tax ROE component of 11.2%. On the Canadian portion, Vector is required to file its negotiated tolls calculation with the NEB on an annual basis. Tolls are calculated on a levelized basis that include a rate of return incentive mechanism based on construction costs and are subject to a rate cap. In 2015, maximum tolls include an ROE component of 10.5% after-tax. Management’s Discussion & Analysis 65
Business Risks The risks identified below are specific to Vector. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks. For risks specific to Alliance Pipeline refer to Sponsored Investments – The Fund Group – Business Risks – Alliance Pipeline. Asset Utilization Vector has been minimally impacted by the excess natural gas supply environment that exists throughout North America mainly as a result of its long-term firm service contracts. Vector has entered into precedent agreements to provide transport service to two proposed pipeline projects that will extend back to the Marcellus/ Utica supply basin. These arrangements, proposed to commence in 2017, will effectively fill all available delivery capacity from current contract roll-offs scheduled through 2019. Current firm service contracts that amount to approximately 52% of long haul capacity are scheduled to expire during 2016 and 2017. Competition Vector faces competition to transport natural gas into Ontario, Canada and other eastern markets from primarily the Marcellus supply region, which may reduce Vector deliveries sourced from its traditional interconnected pipelines in the United States Midwest. Vector manages this risk by focusing on developing long-term relationships with its customers and by providing them value added services. In addition, in 2017, Vector is expected to commence firm service transport based on precedent agreements in place with Rover Pipeline and NEXUS Pipeline projects. Vector will reach its eastern delivery capacity once these projects are in service. Economic Regulation The United States portion of Vector is subject to regulation by the FERC. If tariff rates are protested, the timing and amount of any recovery or refund of amounts recorded on the Consolidated Statements of Financial Position could be different from the amounts that are eventually recovered or refunded. In addition, future profitability of the entities could be negatively impacted. The FERC continues to intensify its oversight of financial reporting, risk standards and affiliate rules and in 2014, the Pipeline and Hazardous Materials Safety Administration (PHMSA) issued new pipeline standards and regulations on managing gas pipeline integrity. The Company continues ongoing dialogue with regulatory agencies and participates in industry groups to ensure it is informed of emerging issues in a timely manner. 66 Enbridge Inc. 2015 Annual Report
Canadian Midstream At December 31, 2015, Canadian Midstream consisted of the Company’s 71% investment in the Cabin Gas Plant (Cabin) located 60 kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin, as well as investments in the Pipestone and Sexsmith gathering systems (together, Pipestone and Sexsmith). The Company has a 100% interest in Pipestone and varying interests (55% to 100%) in Sexsmith and its related sour gas gathering, compression and NGL handling facilities, located in the Peace River Arch (PRA) region of northwest Alberta. The Company is the operator of Cabin. The Canadian Midstream investments are underpinned by 20-year take-or-pay contracts with producers. Return on and of capital is based on the actual costs to purchase or construct the facilities. The Company is not impacted by throughput volumes; however, the Company shares in revenues obtained from available capacity sold to third parties or on volumes that exceed producer take-or-pay levels. Operating costs are passed through to producers. Phase 1 of Cabin is currently 98% completed. Cabin producers are expected to request the Company to commission and start-up Phase 1 once natural gas price recovers to a more economic level to support the Horn River Basin’s dry gas production. Phase 2 construction is approximately 40% complete and is in preservation mode awaiting producer’s requests for completion. In December 2012, the Company started earning fees on its total investment made to date on both Phases 1 and 2. Construction of Pipestone and Sexsmith and related facilities were completed in 2014. In January 2016, the Company reached agreement with Murphy Oil for the purchase of the Tupper Plants within the Montney shale play in northeastern British Columbia, as described under Growth Projects – Commercially Secured Projects. The Tupper Plants, which are currently operating, are designed to process low H2S natural gas and remove a modest level of NGL in order to meet downstream natural gas pipeline specifications. The $0.5 billion transaction is anticipated to close by the second quarter of 2016, following required regulatory approvals. Enbridge will be the operator of the facilities and will provide gas processing services to area producers and to Murphy Oil under a 20-year take-or-pay contract with an option to extend the contract. Results of Operations Canadian Midstream earnings were $41 million for the year ended December 31, 2015 compared with earnings of $23 million for the year ended December 31, 2014. Higher earnings reflected an increase in take-or-pay fees on the Company’s investment in Cabin, Pipestone and Sexsmith. Pipestone earnings also increased as a result of higher volumes that exceeded take-or-pay levels and due to full year of incremental earnings from the final phase placed into service in June 2014. Canadian Midstream earnings were $23 million for the year ended December 31, 2014 compared with earnings of $12 million for the year ended December 31, 2013. The increase in earnings reflected higher fees earned from the Company’s investments in Cabin, Pipestone and Sexsmith. Pipestone earnings were higher due to incremental earnings from the final phase placed into service in 2014 and higher volumes that exceeded take-or-pay levels. Business Risks The risks identified below are specific to Canadian Midstream. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. Asset Utilization Pipestone and Sexsmith are located within the liquids-rich PRA region which has seen significant development by area producers. In 2015, throughput volumes exceeded take-or-pay levels. Cabin is located in the prolific Horn River Basin, one of the largest gas shale plays in North America. The current low gas price environment has slowed development due to the remote location and the lack of NGL content to supplement producer economics. Accelerated development of the Horn River is expected to be primarily tied to the development of LNG exports currently being pursued by Cabin producers. The nearby Cordova Embayment and Liard Basin share similar characteristics as the Horn River; however, they are at an earlier stage of development. The Tupper Plants are located within the core of the Montney shale play, which continues to be developed by a number of producers. Although this area of the Montney contains a lower level of NGL content than others, production is supported by strong economics, the result of high initial production rates, ultimate recoveries and predictable low drilling and completion costs, making it one of the most competitive natural gas production regions in North America. Management’s Discussion & Analysis 67
Enbridge Offshore Pipelines Offshore is comprised of 11 active natural gas gathering and FERC-regulated transmission pipelines and one active oil pipeline with a capacity of 60,000 bpd, in four major corridors in the Gulf of Mexico, extending to deepwater developments. These pipelines include almost 2,100 kilometres (1,300 miles) of underwater pipe and onshore facilities with total capacity of approximately 6.5 bcf/d. Offshore currently moves approximately 45% of total offshore gas production and 55% of deepwater gas production through its systems in the Gulf of Mexico. Results of Operations Offshore adjusted loss was $2 million for each of the years ended December 31, 2015, 2014 and 2013. Offshore adjusted losses for each year reflected persistent weak gas volumes due to decreased production in the Gulf of Mexico. Offshore adjusted losses for 2015 and 2014 also reflected the absence of earnings from the disposals of certain non-core assets that were finalized in March and November 2014, respectively. For the year ended December 31, 2015, Offshore also incurred losses from equity investments in certain joint venture pipelines. Partially offsetting these negative effects in 2015 were earnings from the Jack St. Malo portion of WRGGS that was completed in December 2014. For the year ended December 31, 2014, Offshore adjusted losses were partially offset by incremental earnings from the completion of the Jack St. Malo portion of the WRGGS in December 2014 and cost savings achieved from the Company’s decision not to renew windstorm insurance coverage effective May 2013. Transportation Contracts The primary shippers on the Offshore systems are producers who execute life-of-lease commitments in connection with transmission and gathering service contracts. In exchange, Offshore provides firm capacity for the contract term at an agreed upon rate. The firm capacity made available generally reflects the lease’s maximum sustainable production. The transportation contracts allow the shippers to define a maximum daily quantity (MDQ) over the expected production life. Some contracts have minimum throughput volumes that are subject to ship-or-pay criteria, but also provide the shippers with flexibility, subject to advance notice criteria, to modify the projected MDQ schedule to match current delivery expectations. The majority of long-term transport rates are market-based, with revenue generation directly tied to actual production deliveries. Some of the systems operate under a cost-of-service methodology, including certain lines under FERC regulation. The business model to be utilized for the WRGGS, Big Foot Pipeline, Venice, Heidelberg Pipeline and Stampede Pipeline projects differs from the historic model. These new projects have a base level return that is locked in through either ship-or-pay commitments or fixed demand charge payments. If volumes reach a producer’s anticipated levels, the return on these projects may increase. In addition, Enbridge has minimal capital cost risk on these projects and commercial agreements continue to contain life-of-lease commitments. The WRGGS and Big Foot Pipeline project agreements provide for recovery of actual capital costs to complete the project in fees payable by producers over the contract term. The Stampede Pipeline project provides for a capital cost risk sharing mechanism whereby Enbridge is exposed to a portion of the capital costs in excess of an agreed upon target. Conversely, Enbridge can recover in fees from producers a portion of the capital cost savings below the agreed upon target. Adjustments are allowed for certain of the Heidelberg Pipeline’s project variables that impact its cost, with Enbridge bearing the residual capital cost risk after these adjustments have been applied. Business Risks The risks identified below are specific to Offshore. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. 68 Enbridge Inc. 2015 Annual Report
Asset Utilization A decrease in gas volumes transported by Offshore natural gas pipelines can directly affect revenues and earnings. Low natural gas prices, in part due to the prevalence of onshore shale gas, have resulted in reduced investment in offshore exploration activities and producing infrastructure. Offshore diversifies its risk of declining gas production through the construction of crude oil pipelines. A decline in crude oil prices for a sustained period of time could change the potential for future investment opportunities. Further, a sustained decline in either natural gas or crude oil commodity prices could also impact the ability of the Company to recover its investment in long-lived offshore assets. Competition There is competition for new and existing business in the Gulf of Mexico, with multiple parties competing to construct and operate export pipelines for future deepwater discoveries. Offshore has been able to capture key opportunities, often allowing it to more fully utilize existing capacity. Offshore’s gas pipelines serve a number of strategically located deepwater host platforms, positioning it favourably to make incremental investments for new platform connections and receive additional transportation volumes from new developments that may be tied back to existing host platforms. Offshore is also able to construct pipelines to transport crude oil, diversifying the risk of declining gas production, as demonstrated with the Big Foot Pipeline, Heidelberg Pipeline and Stampede Pipeline projects. Due to natural production decline, offshore pipelines often have available capacity, resulting in significant competition for new developments in the Gulf of Mexico. Competitive dynamics may impact the ability of the Company to recover its investment in long-lived offshore assets. Natural Disaster Incidents Adverse weather, such as hurricanes and tropical storms, may impact Offshore’s financial performance directly or indirectly. Direct impacts may include damage to offshore facilities resulting in lower throughput, as well as inspection and repair costs. Indirect impacts may include damage to third party production platforms, onshore processing plants and pipelines that may decrease throughput on Offshore’s systems. The occurrence of hurricanes in the Gulf of Mexico increases the cost and availability of insurance coverage. On May 1, 2013, the Company elected not to renew windstorm coverage on its Offshore asset portfolio. The Company expects to reassess the market for windstorm coverage and revisit the possible purchase of coverage in future years as the Company’s portfolio of Offshore assets is expected to increase. Enbridge facilities are engineered to withstand hurricane forces and constant monitoring of weather allows for timely evacuation of personnel and shutdown of facilities; however, damages to assets or injuries to personnel may still occur. Other Prior to September 1, 2015, the closing date of the Canadian Restructuring Plan, Other included Lac Alfred, Massif du Sud, Blackspring Ridge and Saint Robert Bellarmin wind projects. Following the close of the Canadian Restructuring Plan on September 1, 2015, Other includes approximately 700 MW of net renewable power generating capacity out of the net enterprise-wide portfolio of nearly 2,000 MW. The balance of the portfolio is held by the Fund Group and earnings contributions from these assets, net of noncontrolling interests, are reflected within Sponsored Investments from the date the assets were transferred to the Fund Group. Also included in Other is the Montana-Alberta Tie-Line (MATL), the Company’s first power transmission asset. Results of Operations Adjusted loss from Other was $1 million for the year ended December 31, 2015 compared with an adjusted loss of $4 million for the year ended December 31, 2014. The 2015 adjusted loss from Other is impacted by the effects of the Canadian Restructuring Plan noted above. Following the closing of the Canadian Restructuring Plan on September 1, 2015, the results of the wind projects listed above are no longer reported in the Gas Pipelines, Processing and Energy Services segment, but are captured in the results of the Fund Group within Sponsored Investments – see Sponsored Investments – The Fund Group. For further details on the Canadian Restructuring Plan refer to Canadian Restructuring Plan. Prior to September 1, 2015, adjusted earnings from Other increased compared with the corresponding 2014 period. The period-over-period increase reflected contributions from new wind farms including the Wildcat and Magic Valley wind farms acquired at the end of 2014 and incremental earnings associated with the purchase of additional interests in the Lac Alfred and Massif du Sud wind projects, which closed in the fourth quarter of 2014 as discussed below, partially offset by higher business development costs not eligible for capitalization within Other. This trend continued into the month of September 2015 and the fourth quarter of 2015; however, adjusted earnings for these periods from the wind projects noted above, as part of the Canadian Restructuring Plan, were reflected in the Fund Group, whereas adjusted earnings for the corresponding 2014 periods were reflected in Gas Pipelines, Processing and Energy Services. Adjusted loss from Other was $4 million for the year ended December 31, 2014 compared with adjusted earnings of $4 million for the year ended December 31, 2013. The decrease in adjusted earnings reflected lower southbound revenues on MATL combined with its higher depreciation expense and financing costs and higher business development costs not eligible for capitalization within Other. Partially offsetting the decrease in adjusted earnings was the positive impact of new wind farms placed into service in the prior years. Lac Alfred and Massif du Sud Wind Projects In September 2014, the Company entered into an agreement to purchase additional interests in the 300-MW Lac Alfred and the 150-MW Massif du Sud from existing partner, EDF EN Canada Inc. Under the agreement, Enbridge invested approximately $225 million to acquire an additional 17.5% interest in Lac Alfred and an additional 30% interest in Massif du Sud. The Lac Alfred transaction closed in October 2014, upon which Enbridge held a 67.5% interest in Lac Alfred. The Massif du Sud transaction closed in December 2014, upon which Enbridge held an 80% interest in Massif du Sud. As described above, effective September 1, 2015, Lac Alfred and Massif du Sud were transferred to the Fund Group under the Canadian Restructuring Plan. Management’s Discussion & Analysis 69
Sponsored Investments Earnings 2015 2014 2013 (millions of Canadian dollars) The Fund Group 509 125 110 Enbridge Energy Partners, L.P. (EEP) 231 197 165 Enbridge Energy, Limited Partnership (EELP) 119 107 38 Adjusted earnings 859 429 313 The Fund Group – make-up rights adjustment (3) –– The Fund Group – changes in unrealized derivative fair value gains/(loss) (174) 3– The Fund Group – unrealized intercompany foreign exchange gains 43 –– The Fund Group – drop down transaction costs (3) (2) – The Fund Group – gain on sale 5 –– The Fund Group – impact of tax rate changes (6) –– The Fund Group – write-down of regulatory balances (3) –– The Fund Group – prior period adjustment (16) –– The Fund Group – employee severance costs (10) –– The Fund Group – Line 9B costs incurred during reversal (1) –– The Fund Group – leak insurance recoveries 13 –– EEP – transfer of contracts (1) –– EEP – changes in unrealized derivative fair value gains/(loss) (6) 5(6) EEP – make-up rights adjustment 1 (1) – EEP – goodwill impairment loss (167) –– EEP – asset impairment loss (11) (2) – EEP – employee severance costs – (1) – EEP – leak insurance recoveries – –6 EEP – tax rate differences/changes – –(3) EEP – valuation allowance on deferred income tax assets (32) –– EEP – leak remediation costs – (12) (44) EEP – gain on sale of non-core assets – –2 EEP – hydrostatic testing (9) –– Earnings attributable to common shareholders 479 419 268 Adjusted earnings from Sponsored Investments were $859 million for the year ended December 31, 2015 compared with $429 million for the year ended December 31, 2014 and $313 million for the year ended December 31, 2013. Within the Fund Group, the material increase in adjusted earnings in 2015 is largely attributable to the transfer of the Canadian liquids business and certain Canadian renewable energy assets from Enbridge, effective September 1, 2015, the closing date of the Canadian Restructuring Plan. 2015 Fund Group adjusted earnings also reflect earnings from natural gas and diluent pipeline interests transferred by Enbridge to the Fund Group in November 2014. The increase in EEP’s adjusted earnings reflected higher throughput and tolls in EEP’s liquids business, including contributions from new assets placed into service in 2014 and 2015 and incremental earnings from the transfer of EELP’s remaining 66.7% interest in Alberta Clipper to EEP on January 2, 2015. Enbridge also benefitted from the completion of new assets placed into service in 2014 and 2015 through its 75% interest in EELP, partially offset by the absence of earnings from Alberta Clipper arising from the transfer noted above. Additional details on items impacting Sponsored Investments include: The Fund Group earnings for 2015 reflected changes in unrealized fair value losses • primarily on derivative financial instruments used to risk manage exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices. The Fund Group earnings for 2015 included employee severance costs in relation • to Enbridge’s enterprise-wide reduction of workforce. 70 Enbridge Inc. 2015 Annual Report
The Fund Group earnings for 2015 included the impact of • a corporate tax rate change in the province of Alberta on opening deferred income tax balances. The Fund Group earnings for 2015 included insurance • recoveries associated with the Line 37 crude oil release, which occurred in June 2013. Refer to Liquids Pipelines –RegionalOilSandsSystem–Line37CrudeOilRelease. EEP earnings for 2015 included a goodwill impairment charge • related to EEP’s natural gas and NGL businesses due to a prolonged decline in commodity prices which has reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL systems. EEP earnings for 2015 reflected an asset impairment charge • of US$63 million ($11 million after-tax attributable to Enbridge) related to EEP’s Berthold rail facility due to contracts that have not been renewed beyond 2016. EEP earnings for 2014 and 2013 included charges related to • estimated costs, before insurance recoveries, associated with the Line 6B crude oil release. Refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – Line 6B Crude Oil Release. Earnings from EEP for 2014 included employee severance • costs triggered by redundancies in EEP’s natural gas and NGL businesses. EEP earnings for 2013 included insurance recoveries associated • with the Line 6B crude oil release. Refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Lines 6A and 6B Crude Oil Releases – Line 6B Crude Oil Release. The Fund Group The Fund Group comprises the Fund, ECT, EIPLP and the subsidiaries of EIPLP. The Fund Group’s primary operations include three core businesses: liquids pipelines transportation and storage (Liquids Transportation and Storage), a natural gas transmission business through its 50% interest in Alliance Pipeline System (Gas Pipelines) and renewable power generation assets (Green Power). Effective September 1, 2015, under the Canadian Restructuring Plan, Enbridge transferred to the Fund Group its Canadian Liquids Pipelines business, comprised of the Canadian Mainline, Regional Oil Sands System, the Canadian portion of the Southern Lights Pipeline and certain residual rights and/or obligations relating to certain terminal and storage assets. For an overview of the Canadian Mainline, Regional Oil Sands System and Southern Lights Pipelines, refer to Liquids Pipelines. Enbridge also transferred to the Fund Group certain Canadian renewable energy assets – refer to Gas Pipelines, Processing and Energy Services. The liquids pipelines assets transferred under the Canadian Restructuring Plan are included the Fund Group’s Liquids Transportation and Storage business effective September 1, 2015. Liquids Transportation and Storage business also operates a crude oil gathering system and trunkline pipeline in southern Saskatchewan and southwestern Manitoba, connecting to Enbridge’s mainline system at Cromer, Manitoba (the Saskatchewan System). In addition, Liquids Transportation and Storage includes the Canadian portion of the Bakken Expansion Pipeline, an interest acquired in Southern Lights Pipeline in November 2014, as well as the Hardisty Contract Terminals and Hardisty Storage Caverns located near Hardisty, Alberta. The Alliance Pipeline, which includes both Alliance Pipeline Canada and Alliance Pipeline US, consists of approximately 3,000 kilometres (1,864 miles) of integrated, high-pressure natural gas transmission pipeline and approximately 860 kilometres (534 miles) of lateral pipelines and related infrastructure. Alliance Pipeline transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub downstream of the Aux Sable NGL extraction and fractionation plant at Channahon, Illinois. Alliance Pipeline US and Alliance Pipeline Canada have annual firm service shipping capacity to deliver 1.455 bcf/d and 1.325 bcf/d, respectively. The Fund Group owns 50% of Alliance Pipeline Canada and 50% of Alliance Pipeline US. Natural gas transported on Alliance Pipeline downstream of the Aux Sable plant can be delivered to two local natural gas distribution systems in the Chicago area and five interstate natural gas pipelines, providing shippers with access to Midwest and eastern natural gas markets. Within Green Power, the Fund Group had interests in over 500 MW of net renewable and alternative power generation capability prior to the closing of the Canadian Restructuring Plan. Following the transfer of additional renewable energy assets from Enbridge under the Canadian Restructuring Plan, Green Power’s net renewable and alternative power generation capability increased to an approximately 1,050 MW at December 31, 2015. The Fund Group Drop Down Transaction In November 2014, the Fund Group completed the acquisition of Enbridge’s 50% interest in Alliance Pipeline US and the subscription for and purchase of Class A units of Enbridge’s subsidiaries that indirectly own the Canadian and United States segments of the Southern Lights Pipeline. The Class A units, which are non-voting and do not confer any governance or ownership rights in Southern Lights Pipeline, will provide a defined cash flow stream to the Fund Group. Total consideration for the transaction was approximately $1.8 billion. Enbridge received on closing approximately $421 million in cash and $461 million in the form of preferred units of ECT, an entity within the Management’s Discussion & Analysis 71
Fund Group. Under the agreement, Enbridge provided bridge debt financing (Bridge Financing) to the Fund Group in the form of an $878 million long-term note payable by the Fund Group and bearing interest of 5.5% per annum. In November 2014, the Fund Group issued $1,080 million of medium-term notes with a portion of these proceeds used to fully repay the Bridge Financing to Enbridge. The Fund Group also issued $421 million of trust units to ENF to fund the cash component of the consideration. Enbridge applied approximately $84 million of cash to acquire additional common shares of ENF, thereby maintaining its 19.9% interest in ENF. Enbridge’s overall economic interest in the Fund Group was reduced from 67.3% to 66.4% upon completion of the transaction. At the time of the transaction, the Fund Group previously owned a 50% investment in Alliance Pipeline Canada. The asset transfers described above occurred between entities under common control of Enbridge, and the intercompany gains realized by the selling entities in the year ended December 31, 2014 have been eliminated from the Consolidated Financial Statements of Enbridge. However, as these transactions involved the sale of shares and partnership units, all tax consequences have remained in consolidated earnings and resulted in a charge of $157 million in 2014. Through this transaction, which essentially resulted in a partial monetization of the assets by Enbridge through sale to noncontrolling interests (being ENF’s public shareholders), Enbridge realized a source of funds of $323 million for the year ended December 31, 2014, as presented within Financing Activities on the Consolidated Statements of Cash Flows. Results of Operations Adjusted earnings for the Fund Group for the year ended December 31, 2015 were $509 million compared with $125 million for the year ended December 31, 2014. The significant increase in adjusted earnings is largely attributable to the transfer of the Canadian liquids business and certain Canadian renewable energy assets from Enbridge as well as Enbridge’s overall economic interest in the Fund Group, which increased to 91.9% on September 1, 2015, following the closing of the Canadian Restructuring Plan. For further discussion on the Canadian Restructuring Plan refer to Canadian Restructuring Plan. Enbridge’s economic interest subsequently decreased to 89.2% upon completion of ENF’s $700 million common share issuance on November 6, 2015. Adjusted earnings from assets transferred under the Canadian Restructuring Plan were impacted by the same reasons as discussed in the Results of Operations sections of these assets within Liquids Pipelines and Gas Pipelines, Processing and Energy Services segments. Also positively impacting adjusted earnings from the Fund Group for the year ended December 31, 2015 were earnings from natural gas and diluent pipeline interests transferred by Enbridge to the Fund Group in the Fund Group Drop Down Transaction in November 2014. Partially offsetting the increase in adjusted earnings were higher financing costs associated with debt raised to acquire the natural gas and diluent pipeline interests, as well as higher income taxes. Adjusted earnings for the Fund Group for the year ended December 31, 2014 were $125 million compared with $110 million for the year ended December 31, 2013. The increase in adjusted earnings reflects the incremental earnings from Enbridge’s transfer of natural gas and diluent pipeline interests to the Fund Group in November 2014, as well as strong performance from the Fund Group’s liquids business. Partially offsetting the increase in adjusted earnings were lower wind resources across several of the Fund Group’s wind farms and higher interest expense associated with an increase in external debt issued in 2014 to support the acquisition of the natural gas and diluent pipeline interests. Finally, adjusted earnings in 2014 were also positively impacted by higher preferred unit distributions received from the Fund Group. Westspur Settlement On April 1, 2013, the Fund Group announced it concluded a settlement (the Settlement) with a group of shippers resulting in new tolls on the Westspur System. At the request of certain shippers that did not execute the Settlement, the NEB did not remove the interim status from the historical tolls and made the new tolls interim as well. A modified agreement was subsequently entered into with substantially all of the shippers, and such shippers requested the NEB make both the historical tolls and the new tolls (collectively, the Tolls) final. On February 6, 2014, the NEB ordered the Tolls final. The Settlement established a toll methodology for an initial term of five years, with additional one year renewal terms unless otherwise terminated. Pursuant to the Settlement, the Tolls on the Westspur System will be fixed and increased annually with reference to an inflation index, subject to throughput remaining within a prescribed volume band close to volumes recently transported on the Westspur System. The Settlement resulted in the discontinuance of rate-regulated accounting for the Westspur System and the Fund Group recorded an after-tax write-down of approximately $12 million ($4 million after-tax attributable to Enbridge) in the first quarter of 2013 related to a deferred regulatory asset that will not be collected under the terms of the Settlement. 72 Enbridge Inc. 2015 Annual Report
Alliance Pipeline Recontracting In 2013, Alliance Pipeline announced a new services framework and the related tolls and tariff provisions required to implement the new services (collectively, New Services Framework). On June 30, 2015 and July 9, 2015, Alliance Pipeline received regulatory approval from the FERC and the NEB, for the United States and Canadian segments of the pipeline, respectively, for the New Services Framework. Shipments under the New Services Framework commenced December 1, 2015. As part of its acceptance of Alliance Pipeline US’ New Services Framework, the FERC set all issues related to the proposed elimination of Authorized Overrun Service and Interruptible Transportation revenue crediting, and the maintenance of Alliance Pipeline US’ existing recourse rates, for hearing. The negotiated reservation rates contained in the Precedent Agreements were converted into negotiated rate transportation contracts as part of the New Services Framework and will not be part of this hearing. As part of the Canadian portion of the New Services Framework, the NEB granted pricing discretion for interruptible transportation and seasonal firm service with all associated revenues accruing to Alliance Pipeline Canada. Alliance Pipeline has successfully re-contracted its annual firm service capacity with an average contract length of approximately five years. Pursuant to the New Services Framework, Alliance Pipeline retains exposure to potential variability in certain future costs and market based revenues generated from services provided beyond annual firm transport service. As such, the majority of Alliance Pipeline’s operations no longer meet all of the criteria required for the continued application of rate-regulated accounting treatment and a derecognition of regulatory balances as at June 30, 2015 was required. The Fund Group recorded an after-tax write-down of approximately $10 million ($3 million after-tax attributable to Enbridge) during the second quarter of 2015. Business Risks The risks identified below are specific to the Fund Group’s three core businesses: Liquids Transportation and Storage; Alliance Pipeline; and Green Power. For business risks related to the Canadian Mainline and Regional Oil Sands System, refer to Liquids Pipelines – Business Risks. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks. Liquids Transportation and Storage Asset Utilization Asset utilization risk for the Fund Group’s liquids business shares similar risk characteristics to Liquids Pipelines as changing market fundamentals, capacity bottlenecks, including insufficient capacity downstream on the Canadian Mainline, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of the Fund Group’s assets. The Fund Group is also exposed to throughput risk under certain tolling agreements applicable to the Saskatchewan System assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions, outside of the Fund Group’s control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on the Saskatchewan System. The Fund Group seeks to mitigate utilization risks within its control, including working with the shipper community on its tolling agreements. Additionally, volume risk is somewhat mitigated for the Westspur System due to the fact that toll surcharges or discounts will be applied should throughput increase or decrease on a sustained basis outside a pre-defined band set as defined in the agreement. Management’s Discussion & Analysis 73
Competition Liquids Transportation and Storage, including the Saskatchewan System, faces competition in pipeline transportation from other pipelines as well as other forms of transportation, most notably rail. These alternative transportation options could charge rates or provide service to locations that result in greater netbacks for shippers, thereby reducing shipments on the Saskatchewan System or resulting in pressure to reduce tolls. The Saskatchewan System’s right-of-way and expansion efforts provide a competitive advantage. Operational and Economic Regulation 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 the Fund Group’s assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on the Fund Group’s future earnings and the cost related to the construction of new projects. The Company believes operational regulation risk is mitigated by active monitoring and consulting on potential regulatory requirement changes with the respective regulators or through industry associations. The Company also develops robust response plans to regulatory changes or enforcement actions. While the Company believes the safe and reliable operation of its assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators to make unilateral decisions that could have a financial impact on the Fund Group. In relation to economic regulations, certain pipelines within the Saskatchewan System are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings and the success of expansion projects. Delays in regulatory approvals could result in cost escalations and construction delays. Changes in regulation, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could adversely affect the results of operations of the Fund Group and could adversely impact the timing and amount of recovery or settlement of regulatory balances. The Company believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers. The Company also involves its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations as well as in the establishment of tariffs and tolls on new and existing pipelines. However, despite the efforts of the Company to mitigate economic regulation risk, there remains a risk that a regulator could overturn long-term agreements between the Company and shippers or deny the approval and permits for new projects. Alliance Pipeline Asset Utilization Currently, natural gas pipeline capacity out of the WCSB exceeds supply. Alliance Pipeline to date has been relatively unaffected by the excess supply environment as the Alliance Pipeline was successfully recontracted. Further, Alliance Pipeline is well positioned to deliver incremental liquids-rich gas production from developments in the Montney, Duvernay and Bakken regions to large natural gas markets and, following extraction and fractionation at the Aux Sable NGL extraction and fractionation plant, to deliver NGL to growing markets. As noted above, Alliance Pipeline’s New Services Framework also allows for the provision of services beyond annual firm transport service, at market rates, further supporting asset utilization. Competition Alliance Pipeline faces competition for pipeline transportation services to the Chicago area from both existing pipelines and proposed pipeline projects from existing and new gas developments throughout North America. Any new or upgraded pipelines could either allow shippers greater access to natural gas markets or offer natural gas transportation services that are more desirable than those provided by the Alliance Pipeline because of location, facilities or other factors. In addition, any new, existing, or upgraded pipelines could charge tolls or rates or provide transportation services to locations that result in greater net profit for shippers, with the effect of reducing future supply for the Alliance Pipeline. The ability of the Alliance Pipeline to cost-effectively transport liquids-rich gas and its proximity to the liquids-rich Montney, Duvernay and Bakken plays serve to enhance its competitive position. Economic Regulation Alliance Pipeline is subject to regulation by the NEB in Canada and the FERC in the United States. Under the New Services Framework, effective December 1, 2015, Alliance Pipeline has contracted with shippers under terms as approved by the NEB in Canada and the FERC in the United States. Firm service tolls are fixed for the duration of the contracts’ terms. Green Power Asset Utilization Earnings from Green Power assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Green Power projects are predicted using long-term historical data, wind and solar resources will be subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at any of the Green Power facilities could lead to decreased earnings for the Company. Additionally, inefficiencies or interruptions of Green Power facilities due to operational disturbances or outages could also impact earnings. The Company mitigates the risk of operational availability by establishing Operations and Maintenance contracts with the original equipment manufacturers that include a negotiated operational performance asset guarantee. The Company also monitors the operational performance and reliability of the assets on a 24-hour basis. 74 Enbridge Inc. 2015 Annual Report
Power produced from Green Power assets is also often sold to a single counterparty under PPA or other long-term pricing arrangements. In this respect, the performance of the Green Power assets is dependent on each counterparty performing its contractual obligations under the PPA or pricing arrangement applicable to it. Competition The Fund Group’s Green Power assets operate in the Canadian power market, which is subject to competition and the supply and demand balance for power in the provinces in which they operate. The renewable energy market sector includes large utilities and small independent power producers, which are expected to aggressively compete with the Company for project development opportunities. Enbridge Energy Partners, L.P. EEP owns and operates crude oil and liquid petroleum transportation and storage assets; natural gas and NGL gathering, treating, processing, transportation assets; and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Canadian Mainline in the United States, the Mid-Continent Crude Oil System consisting of an interstate crude oil pipeline and storage facilities, a crude oil gathering system and interstate pipeline system in North Dakota and natural gas assets located primarily in Texas. Subsidiaries of Enbridge provide services to EEP in connection with the operation of its liquids assets, including the Lakehead System. Economic Interest Enbridge’s ownership interest in EEP is impacted by EEP’s issuance and sale of its Class A common units. To the extent Enbridge does not fully participate in these offerings, the Company’s economic interest in EEP is reduced. At December 31, 2015, Enbridge’s economic interest in EEP was 35.7% (2014 – 33.7%; 2013 – 20.6%). The Company’s average economic interest in EEP during 2015 was 36.0% (2014 – 27.3%; 2013 – 21.1%). The increase in Enbridge’s economic interest in EEP largely reflected the impact of the restructuring of EEP’s equity in 2014 as discussed below. Additionally, Enbridge also holds a US$1.2 billion investment in EEP preferred units. For further discussion, refer to Sponsored Investments –Enbridge Energy Partners, L.P. – EEP Preferred Unit Private Placement and Joint Funding Option Exercise. Common Unit Issuance In March 2015, EEP completed the issuance of eight million Class A common units for gross proceeds of approximately US$294 million before underwriting discounts and commissions and offering expenses. Enbridge did not participate in the issuance; however, the Company made a capital contribution of US$6 million to maintain its 2% general partner (GP) interest in EEP. EEP used the proceeds from the offering to fund a portion of its capital expansion projects and for general partnership purposes. Equity Restructuring In June 2014, EEP and Enbridge announced an agreement to restructure EEP’s equity with the objective of enhancing the economics of EEP’s investment projects and growth opportunities, while at the same time re-establishing EEP as a strong sponsored vehicle and as an effective source of funding for Enbridge via future asset monetization. Effective July 1, 2014, Enbridge Energy Company, Inc. (EECI), a wholly-owned subsidiary of Enbridge and the GP of EEP, irrevocably waived its then existing IDR in excess of its 2% GP interest in exchange for 66.1 million Class D units and 1,000 Incentive Distribution Units (IDU) (collectively, the Equity Restructuring). The GP share of incremental cash distributions decreased from 48% of all distributions in excess of US$0.4950 per unit per quarter down to 23% of all distributions in excess of EEP’s quarterly distribution of US$0.5435 per unit per quarter. The Class D units carry a distribution equal to the quarterly distribution on the Class A common units. The 2014 third and fourth quarter distributions on the Class D units were adjusted to provide Enbridge with an aggregate distribution in 2014 equal to the distribution on its IDR as if the Equity Restructuring had not occurred. The IDU is not entitled to a distribution initially and in the event of any decrease in the Class A common unit distribution below US$0.5435 per unit in any quarter during the next five years, the distribution on the Class D units will be reduced to the amount which would have been received by Enbridge under the IDR as if the Equity Restructuring had not occurred. The Class D units have a notional value per unit equivalent to the closing market price of the Class A common units on June 17, 2014 (Notional Value) and have the same voting rights as the Class A common units. The Class D units are convertible on a one-for-one basis into Class A common units at any time on or after the fifth anniversary of the closing date, at the holder’s option. In the event of a liquidation event (or any merger or other extraordinary transaction), the Class D unitholders will have a preference in liquidation equal to 20% of the Notional Value, with such preference being increased by an additional 20% on each anniversary of the closing date, resulting in a liquidation preference equal to 100% of the Notional Value on the fourth anniversary of the closing date. The Class D units will be redeemable after 30 years from issuance in whole or in part at EEP’s option for either a cash amount equal to the Notional Value per unit or newly issued Class A common units with an aggregate market value at redemption equal to 105% of the aggregate Notional Value of the Class D units being redeemed. Management’s Discussion & Analysis 75
Distributions EEP makes quarterly distributions of its available cash to its common unitholders. Under the Partnership Agreement, EECI as GP receives incremental incentive cash distributions, which represent incentive income on the portion of cash distributions (on a per unit basis) that exceed certain target thresholds. Distributions to common unitholders and the GP are made as follows: Unitholders including Enbridge GP Interest Quarterly cash distributions per unit: Up to US$0.5345 per unit 98% 2% Target – cash distributions over US$0.5345 per unit 75% 25% Prior to the Equity Restructuring, distributions to common unitholders and the GP were made on the basis of the following target thresholds: Unitholders including Enbridge GP Interest Quarterly cash distributions per unit: Upto US$0.2950perunit 98% 2% Firsttarget – US$0.2950 per unitup to$0.3500 per unit 85% 15% Second target – US$0.3500 per unit up to $0.4950 per unit 75% 25% Over second target – cash distributions greater than US$0.4950 per unit 50% 50% In July 2014, EEP increased its quarterly distribution from US$0.5435 per unit to common unitholders to US$0.5550. On December 23, 2014, EEP announced it would further increase its quarterly distribution to US$0.5700 per unit to common unitholders following the announcement that the Alberta Clipper Drop Down was finalized. Refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Alberta Clipper Drop Down. In 2015, Enbridge received from EEP, incentive distributions of US$19 million (2014 – US$39 million; 2013 – US$130 million). Also in 2015, Enbridge received distributions of US$195 million from Class D units (2014 – US$108 million) and Class E units which were issued under the Equity Restructuring and Alberta Clipper Drop Down transactions. Results of Operations Adjusted earnings from EEP were $231 million for the year ended December 31, 2015 compared with $197 million for the year ended December 31, 2014. The adjusted earnings increase reflected higher throughput and tolls in EEP’s liquids business, as well as contributions from new assets placed into service in 2014 and 2015, the most prominent being the expansion of the Company’s mainline system completed in July 2015 and the replacement and expansion of Line 6B completed in 2014. In addition, EEP adjusted earnings reflected incremental earnings from the transfer on January 2, 2015 of the remaining 66.7% interest in Alberta Clipper previously held by Enbridge through EELP. Partially offsetting the increase in adjusted earnings in EEP’s liquids business were higher operating and administrative costs, incremental power costs associated with higher throughput and higher depreciation expense from an increased asset base. Also contributing to higher earnings in 2015 were distributions from Class D units and IDU which were issued to Enbridge in July 2014 under the equity restructuring transaction described above and from Class E units which were issued in January 2015 in connection with the transfer of Alberta Clipper. Finally, the 2015 results reflected lower volumes within EEP’s natural gas and NGL businesses primarily as a result of reduced drilling programs by producers. EEP holds its natural gas and NGL businesses directly and indirectly through its partially-owned subsidiary, MEP. Adjusted earnings from EEP were $197 million for the year ended December 31, 2014 compared with $165 million for the year ended December 31, 2013. Within EEP’s liquids business, adjusted earnings increased primarily as a result of new assets placed into service during 2013 and 2014, combined with higher throughput and tolls on its major liquids pipelines. New assets placed into service included the replacement and expansion of Line 6B as part of Enbridge and EEP’s Eastern Access initiative, as well as the Line 6B 75-mile replacement program. Within EEP’s North Dakota system, the Bakken Expansion 76 Enbridge Inc. 2015 Annual Report
Sponsored Investments Fort St. John Fort St. John Fort McMurray Cheecham Athabasca System Edmonton Hardisty CANADA Calgary Alliance Pipeline (Canada) Enbridge Mainline System Gretna North Dakota System Clearbrook Minot Enbridge Superior Mainline System Montreal Alliance Pipeline (US) Lakehead System Toronto Sarnia UNITED STATES OF AMERICA Chicago Toledo Flanagan Patoka Wood River Cushing Ozark Pipeline Midcoast Energy Partners Natural Gas Assets New Orleans Houston Enbridge Energy Partners, L.P. 1 The Fund Group M The Fund Group Legacy Assets E Enbridge Inc. X Wind Assets I 1 C Wind Assets—The Fund Group O Solar Assets 1 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business to the Fund Group within Sponsored Investments. For further details, refer to Canadian Restructuring Plan. Management’s Discussion & Analysis 77
and Access programs, which enhance crude oil gathering capabilities in the Bakken region, were also a significant contributor to the adjusted earnings growth. Positive factors experienced by Canadian Mainline in 2014 as noted earlier also resulted in higher 2014 throughput on EEP’s Lakehead System. Partially offsetting the increase in adjusted earnings in EEP’s liquids business were incremental power costs associated with higher throughput, higher depreciation expense from an increased asset base and higher operating and administrative costs primarily associated with a larger workforce partially offset by lower pipeline integrity costs. Within EEP’s natural gas and NGL businesses, which it holds directly and indirectly through its partially-owned subsidiary, MEP, lower volumes mainly due to decreased drilling activity had a negative impact on adjusted earnings. Finally, EEP’s contribution to Enbridge’s adjusted earnings reflected higher earnings from Enbridge’s May 2013 investment in preferred units of EEP, higher incentive distributions and distributions from Class D units which were issued under the Equity Restructuring. Alberta Clipper Drop Down On January 2, 2015, Enbridge completed the transfer of its 66.7% interest in the United States segment of the Alberta Clipper Pipeline, held through a wholly-owned Enbridge subsidiary in the United States, to EEP. At the time of the transfer, EEP already owned the remaining 33.3% interest in the United States segment of Alberta Clipper. Aggregate consideration for the transfer was US$1 billion, consisting of approximately US$694 million of Class E equity units issued to Enbridge by EEP and the repayment of approximately US$306 million of indebtedness owed to Enbridge. The terms of the transfer were reviewed and recommended by an independent committee of EEP. The Class E units issued to Enbridge are entitled to the same distributions as the Class A common units held by the public and are convertible into Class A common units on a one-for-one basis at Enbridge’s option. However, the Class E units are not entitled to distributions with respect to the quarter ended December 31, 2014. The Class E units are redeemable at EEP’s option after 30 years, if not converted earlier by Enbridge. The units have a liquidation preference equal to their notional value at December 23, 2014 of US$38.31 per unit, which was determined based on the trailing five-day volume-weighted average price of EEP’s Class A common units. The aggregate consideration of US$1 billion corresponded to an approximate 10.7 times multiple of then expected 2015 Alberta Clipper Earnings before interest, tax, depreciation and amortization (EBITDA). If after two years, the cumulative adjusted EBITDA of the Alberta Clipper Pipeline for fiscal years 2015 and 2016 is more than five percent below the EBITDA projections for those years, a number of Class E units representing US$50 million of value will be cancelled by EEP effective as of June 15, 2017 for no consideration. The United States segment of the Alberta Clipper Pipeline is a 523-kilometre (325-mile), 36-inch diameter crude oil pipeline from the United States border near Neche, North Dakota to Superior, Wisconsin. The initial capacity of the line was 450,000 bpd and was constructed under the terms of a joint funding agreement under which Enbridge funded two-thirds of the capital costs in return for a corresponding economic interest in the earnings and cash flow from the investment. In 2015, the line was expanded in two phases 78 Enbridge Inc. 2015 Annual Report to a capacity of 800,000 bpd through the addition of increased pumping horsepower; however, EEP is awaiting an amendment to the current Presidential border crossing permit to allow for operation of Alberta Clipper Pipeline at its currently planned operating capacity of 800,000 bpd. The required expansion investments are subject to separate joint funding arrangements between Enbridge and EEP and were not included as part of the above noted drop down transaction. Refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Mainline Expansion. Lakehead System Lines 6A and 6B Crude Oil Releases Line 6B Crude Oil Release On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Kalamazoo River via Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 61 kilometres (38 miles) of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. EEP continues to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives EEP is undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. On March 14, 2013, EEP received an order from the EPA (the EPA Order) which required additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. In February 2015, the EPA acknowledged EEP’s completion of the EPA Order. In November 2014, regulatory authority was transferred from the EPA to the Michigan Department of Environmental Quality (MDEQ). The MDEQ has oversight over the submerged oil reassessment, sheen management and sediment trap monitoring and maintenance activities through a Kalamazoo River Residual Oil Monitoring and Maintenance Work Plan. In May 2015, EEP reached a settlement with the MDEQ and the Michigan Attorney General’s offices regarding the Line 6B crude oil release. As stipulated in the settlement, EEP agrees to: (1) provide at least 300 acres of wetland through restoration, creation, or banked wetland credits, to remain as wetland in perpetuity; (2) pay US$5 million as mitigation for impacts to the banks, bottomlands, and flow of Talmadge Creek and the Kalamazoo River for the purpose of enhancing the Kalamazoo River watershed and restoring stream flows in the River; (3) continue to reimburse the State of Michigan for costs arising from oversight of EEP activities since the release; and (4) continue monitoring, restoration and invasive species control within state-regulated wetlands affected by the release and associated response activities. The timing of these activities is based upon the work plans approved by the State of Michigan. As at December 31, 2015, EEP’s total cost estimate for the Line 6B crude oil release was US$1.2 billion ($193 million after-tax attributable to Enbridge), which is unchanged since December 31, 2014. As at December 31, 2014, the total cost estimate for the Line 6B crude oil release increased by US$86 million as compared to December 31, 2013. The total cost increase of US$86 million during the year ended
December 31, 2014, was primarily related to the MDEQ approved Schedule of Work, completion of the dredge activities near Ceresco and Morrow Lake and estimated civil penalties under the Clean Water Act of the United States (Clean Water Act), as described below under Legal and Regulatory Proceedings. Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at December 31, 2015. Despite the efforts EEP has made to ensure the reasonableness of its estimates, there continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies, in addition to fines and penalties and expenditures associated with litigation and settlement of claims. Line 6A Crude Oil Release A release of crude oil from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. EEP estimates that approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Some of the released crude oil went onto a roadway, into a storm sewer, a waste water treatment facility and then into a nearby retention pond. All but a small amount of the crude oil was recovered. EEP completed excavation and replacement of the pipeline segment and returned it to service on September 17, 2010. EEP has completed the cleanup, remediation and restoration of the areas affected by the release. On October 21, 2013, the National Transportation Safety Board publicly posted their final report related to the Line 6A crude oil release which states the probable cause of the crude oil release was erosion caused by a leaking water pipe resulting from an improperly installed third-party water service line below EEP’s oil pipeline. The total estimated cost for the Line 6A crude oil release was approximately US$51 million ($7 million after-tax attributable to Enbridge) before insurance recoveries and excluding fines and penalties. These costs included emergency response, environmental remediation and cleanup activities with the crude oil release. As at December 31, 2015, EEP has no remaining estimated liability. Insurance EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates which renews throughout the year. On May 1 of each year, the insurance program is renewed and includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents excluding costs for fines and penalties. A majority of the costs incurred in connection with the crude oil release for Line 6B are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability for Enbridge and its affiliates. Including EEP’s remediation spending through December 31, 2015, costs related to Line 6B exceeded the limits of the coverage available under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy. As at December 31, 2015, EEP has recorded total insurance recoveries of US$547 million ($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million aggregate limit. EEP will record receivables for additional amounts it claims for recovery pursuant to its insurance policies during the period it deems recovery to be probable. In March 2013, EEP and Enbridge filed a lawsuit against the insurers of US$145 million of coverage, as one particular insurer is disputing the recovery eligibility for costs related to EEP’s claim on the Line 6B crude oil release and the other remaining insurers assert that their payment is predicated on the outcome of the recovery from that insurer. EEP received a partial recovery payment of US$42 million from the other remaining insurers and amended its lawsuit such that it now includes only one insurer. Of the remaining US$103 million coverage limit, US$85 million is the subject matter of a lawsuit against one particular insurer. In March 2015, Enbridge reached an agreement with that insurer to submit the US$85 million claim to binding arbitration. The recovery of the remaining US$18 million is awaiting resolution of that arbitration, which is not scheduled to occur until the fourth quarter of 2016. While EEP believes those costs are eligible for recovery, there can be no assurance that EEP will prevail in the arbitration. Enbridge renewed its comprehensive property and liability insurance programs under which the Company is insured through April 30, 2016 with a liability program aggregate limit of US$860 million, which includes sudden and accidental pollution liability. In the unlikely event multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among Enbridge entities on an equitable basis based on an insurance allocation agreement among Enbridge and its subsidiaries. Legal and Regulatory Proceedings A number of United States governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Five actions or claims are pending against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release. Based on the current status of these cases, the Company does not expect the outcome of these actions to be material to its results of operations or financial condition. As at December 31, 2015, included in EEP’s estimated costs related to the Line 6B crude oil release is US$44 million in fines and penalties. Of this amount, US$40 million relates to civil penalties under the Clean Water Act. While no final fine or penalty has been assessed or agreed to date, EEP believes that, based on the best information available at this time, the US$40 million represents an estimate of the minimum amount which may be assessed, excluding costs of injunctive relief that may be agreed to with the relevant governmental agencies. Given the complexity of settlement negotiations, which EEP expects will continue, and the limited information available to assess the matter, EEP is unable to reasonably estimate the final penalty which might be incurred or to reasonably estimate a range of outcomes at this time. Injunctive relief is likely to include further measures directed toward enhancing spill prevention, leak detection and emergency response to environmental events. The cost of compliance with such measures, when combined with Management’s Discussion & Analysis 79
any fine or penalty, could be material. EEP has entered into a tolling agreement with the applicable governmental agencies and discussions with these governmental agencies regarding fines, penalties and injunctive relief are ongoing. In June 2015, Enbridge reached a separate agreement with the United States (Federal Natural Resources Damages Trustees), State of Michigan (State Natural Resources Damages Trustees), Match-E-Be-Nash-She-Wish Band of the Potawatomi Indians, and the Nottawaseppi Huron Band of the Potawatomi Indians, and paid approximately US$4 million that was accrued to cover a variety of projects, including the restoration of 175 acres of oak savanna in the Fort Custer State Recreation Area and wild rice beds along the Kalamazoo River. One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court in connection with this crude oil release. On February 20, 2015, EEP agreed to a consent order releasing it from any claims, liability, or penalties. Lakehead System Line 14 Crude Oil Release On July 27, 2012, a release of crude oil was detected on Line 14 of EEP’s Lakehead System near Grand Marsh, Wisconsin. The estimated volume of oil released was approximately 1,700 barrels. EEP received a Corrective Action Order (CAO) from the PHMSA on July 30, 2012, followed by an amended CAO on August 1, 2012. Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. During the fourth quarter of 2013, EEP received approval from the PHMSA to remove the pressure restrictions and to return to normal operating pressures for a period of 12 months. In December 2014, the PHMSA again considered the status of the pipeline in light of information they acquired throughout 2014. On December 9, 2014, EEP received a letter from the PHMSA approving its request to continue the normal operation of Line 14 without pressure restrictions. EEP has no remaining estimated liability for this release. EEP Preferred Unit Private Placement and Joint Funding Option Exercise In May 2013, Enbridge invested US$1.2 billion in preferred units of EEP to reduce the amount of near-term external funding required by EEP to fund its share of the Company’s organic growth program. On July 30, 2015, Enbridge and EEP reached an agreement to extend the deferral of quarterly cash distribution on these preferred units. The first quarterly cash distribution will now occur in the third quarter of 2018 and the deferred distribution will now be payable in equal amounts over a 12-quarter period beginning the first quarter of 2019. Concurrent with the issuance in May 2013, EEP also announced it expected to exercise its option in each of the Eastern Access and Lakehead System Mainline Expansion joint funding agreements to reduce its economic interest and associated funding in the respective projects. On June 28, 2013, EEP exercised each of the options and both projects are now being funded 75% by Enbridge and 25% by EEP. EEP will retain the option to increase its economic interest back up to 40% in each project within one year of the final project in-service dates. Midcoast Energy Partners, L.P.—Initial Public Offering and Drop Down of Additional Interests EEP holds its natural gas and NGL midstream assets through a combination of direct holding and indirect holdings through MEP, a publicly listed partnership trading on the New York Stock Exchange. EEP’s direct interest in entities or partnerships holding the natural gas and NGL midstream operations is 48%, with the remaining ownership held by MEP. EEP retains a 2% GP interest, an approximate 52% limited partner interest and all IDR in MEP. In May 2013, EEP formed MEP as its wholly-owned subsidiary. Subsequently, on November 13, 2013, MEP completed its initial public offering of 18.5 million Class A common units representing limited partner interests and subsequently issued an additional 2.8 million Class A common units pursuant to an underwriters’ over-allotment option. MEP received proceeds of approximately US$355 million. Upon finalization of the offering, MEP’s initial assets consisted of an approximate 39% ownership interest in EEP’s natural gas and NGL midstream business. EEP retained a 2% GP interest, an approximate 52% limited partner interest and all IDR in MEP, in addition to its 61% direct interest in the natural gas and NGL midstream assets. On July 1, 2014, EEP completed the sale of an additional 12.6% limited partnership interest in its natural gas and NGL midstream business to MEP for cash proceeds of US$350 million. Upon finalization of this transaction, EEP continued to retain its interest in MEP as noted above; however, EEP’s direct interest in entities or partnerships holding the natural gas and NGL midstream operations reduced from 61% to 48%, with the remaining ownership held by MEP. The completion of these transactions resulted in a partial monetization of EEP’s natural gas and NGL midstream business through sale to noncontrolling interests (being MEP’s public unitholders). The proceeds from the drop down provided EEP a cost-effective funding alternative to execute its current liquids pipeline organic growth program. Intercompany Accounts Receivable Sale On June 28, 2013, certain of EEP’s subsidiaries entered into a Receivables Purchase Agreement (the Receivables Agreement) with a wholly-owned subsidiary of Enbridge, whereby Enbridge will purchase on a monthly basis certain trade and accrued receivables of such subsidiaries through December 2016. Pursuant to the Receivables Agreement, as amended on September 20, 2013, and again on December 2, 2013, at any one point the accumulated purchases, net of collections, shall not exceed US$450 million. The primary objective of the accounts receivable transaction is to further enhance EEP’s available liquidity and its cash available from operations for payment of distributions during the next few years until EEP’s large growth capital commitments are permanently funded, as well as to provide an annual saving in EEP’s cost of funding during this period. 80 Enbridge Inc. 2015 Annual Report
Enbridge Energy Management, L.L.C. Share Issuance Enbridge’s ownership in EEP is held through a combination of direct interest, including a 2% GP interest, and indirect interest through EEM. In 2013, EEM completed two separate issuances of Listed Shares. In March 2013, EEM completed the issuance of 10.4 million Listed Shares for net proceeds of approximately US$273 million and in September 2013, EEM completed a further issuance of 8.4 million Listed Shares for net proceeds of approximately US$236 million. Enbridge did not purchase any of the offered shares. EEM subsequently used the net proceeds from each of the offerings to invest in an equal number of i-units of EEP. In connection with these issuances, the Company made capital contributions of US$6 million and US$5 million in March and September 2013, respectively, to maintain its 2% GP interest in EEP. The proceeds from the issuances were used by EEP to repay commercial paper, to finance a portion of its capital expansion program relating to its core liquids and natural gas systems and for general partnership purposes. Enbridge Energy, Limited Partnership EELP holds assets that are jointly funded by Enbridge and EEP. Included within EELP is the United States segment of Alberta Clipper Pipeline. The United States portion of the Alberta Clipper Pipeline connects with the Canadian portion of Alberta Clipper Pipeline at the border near Neche, North Dakota and provides transportation service to Superior, Wisconsin. Enbridge funded 66.7% of the project’s equity requirements through EELP, while 66.7% of the debt funding was made through EEP. On January 2, 2015, Enbridge transferred its 66.7% interest in the United States segment of Alberta Clipper to EEP. Refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Alberta Clipper Drop Down. Also within EELP is Enbridge’s partnership interest in both the Eastern Access and Lakehead System Mainline Expansion projects. In 2012, EELP amended and restated its limited partnership agreement to establish a series of additional partnership interests in both the Eastern Access and Lakehead System Mainline Expansion projects. Both of these projects will be funded 75% by Enbridge and 25% by EEP. For further details on the respective projects, refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access and Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Mainline Expansion. Results of Operations Earnings from EELP were $119 million for the year ended December 31, 2015 compared with $107 million for the year ended December 31, 2014. Adjusted earnings from EELP increased in 2015 due to contributions from assets recently placed into service, most notably the expansion of the Company’s mainline system completed in July 2015 and the expansion of Line 6B completed in phases during 2014 as part of the Company’s Eastern Access Program. Partially offsetting the increase in 2015 earnings was the absence of earnings from EELP’s interest in Alberta Clipper which was transferred to EEP on January 2, 2015. Earnings from EELP were $107 million for the year ended December 31, 2014 compared with $38 million for the year ended December 31, 2013. Higher earnings reflected contributions from assets recently placed into service, most notably the expansion of Line 6B completed in phases during 2014 as part of the Company’s Eastern Access Program. Higher earnings from Eastern Access also reflected a higher surcharge rate due to the Lakehead System filing delay and other true-up adjustments. Also positively impacting earnings were higher tolls on Alberta Clipper. Business Risks The risks identified below are specific to EEP and EELP. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. Asset Utilization Asset utilization risk for EEP’s liquids business shares similar risk characteristics to Liquids Pipelines as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of EEP’s assets. The profitability of EEP’s liquids business depends to some extent on the throughput of products transported on its pipeline systems, and a decrease in volumes transported can directly and adversely affect revenues and earnings. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative energy sources and global supply disruptions, outside of EEP’s control can impact both the supply of and demand for crude oil and other liquid hydrocarbons transported on EEP’s pipelines. However, the long-term outlook for Canadian crude oil production, particularly from western Canada, and increasing United States domestic production are expected to maintain a steady supply of crude oil. EEP seeks to mitigate utilization constraints within its control. The market access and expansion projects under development are expected to reduce capacity bottlenecks and introduce new markets for customers. EEP seeks to optimize capacity and throughput on its existing assets by working with the shipper community to enhance scheduling efficiency and communications, as well as making continuous improvements to scheduling models and timelines to maximize throughput. EEP’s natural gas gathering assets are also subject to market fundamentals affecting natural gas, NGL and related products. Commodity prices impact the willingness of natural gas producers to invest in additional infrastructure to produce natural gas and, with current low natural gas prices, infrastructure plans have been increasingly deferred or cancelled. These assets are also subject to competitive pressures from third-party and producer-owned gathering systems. Supply for the marketing operations depends to a large extent on the natural gas reserves and rate of drilling within the areas served by the natural gas business. Demand is typically driven by weather-related factors, with respect to power plant and utility customers, and industrial demand. EEP’s marketing business uses third party storage to balance supply and demand factors. Management’s Discussion & Analysis 81
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 has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on EEP’s future earnings and the cost related to the construction of new projects. The Company believes operational regulation risk is mitigated by active monitoring and consulting on potential regulatory requirement changes with the respective regulators or through industry associations. The Company also develops robust response plans to regulatory changes or enforcement actions. While the Company believes the safe and reliable operation of its assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators to make unilateral decisions that could have a financial impact on EEP. EEP’s economic regulation is driven primarily through its ownership of interstate oil pipelines and certain activities within its intrastate natural gas pipelines, which are regulated by the FERC or state regulators. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on EEP’s revenues and earnings. Delays in regulatory approvals could result in cost escalations and construction delays, which also negatively impact EEP’s operations. Additionally, while EEP’s gas gathering pipelines are not currently subject to FERC rate regulation, proposals to more actively regulate intrastate gathering pipelines are currently being considered in certain of the states in which EEP operates. In addition, the FERC has also taken an interest in regulating gas gathering systems that connect into interstate pipelines. The Company believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers. The Company also involves its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations as well as in the establishment of tariffs and tolls on new and existing pipelines. However, despite the efforts of the Company to mitigate economic regulation risk, there remains a risk that a regulator could overturn long-term agreements between the Company and shippers or deny the approval and permits for new projects. 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. 82 Enbridge Inc. 2015 Annual Report
Corporate Earnings 2015 2014 2013 (millions of Canadian dollars) Noverco 50 43 54 Other Corporate (33) (69) (82) Adjusted earnings/(loss) 17 (26) (28) Noverco – changes in unrealized derivative fair value gains/(loss) (9) (5) 4 Other Corporate – changes in unrealized derivative fair value loss (520) (378) (306) Other Corporate – loss on de-designation of interest rate hedges in connection with the Canadian Restructuring Plan (247) –– Other Corporate – transaction costs relating to the Canadian Restructuring Plan (16) –– Other Corporate – deferred income tax out-of-period adjustments 71 –– Other Corporate – foreign tax recovery – –4 Other Corporate – impact of tax rate changes 44 –18 Other Corporate – drop down transaction costs (6) (6) – OtherCorporate–assetimpairmentloss (2) –(6) Other Corporate – tax on intercompany gains on sale of partnership units (39) (157) – Other Corporate – gain on sale of investment – 14 – Other Corporate – employee severance costs (19) –– Other Corporate – prior period adjustment (6) –– Loss attributable to common shareholders (732) (558) (314) Total adjusted earnings from Corporate were $17 million for the year ended December 31, 2015 compared with adjusted losses of $26 million for the year ended December 31, 2014 and adjusted losses of $28 million for the year ended December 31, 2013. Stronger operating earnings from Gaz Metro Limited Partnership (Gaz Metro) due to a favourable United States/Canada foreign exchange rate and incremental earnings from new assets drove higher Noverco adjusted earnings in 2015 compared with 2014. Noverco adjusted earnings in 2013 included favourable impacts of a small one-time gain on sale of an investment and equity earnings true-up adjustment. Adjusted loss in Other Corporate decreased over the past two years, reflecting lower net Corporate segment finance costs, partially offset by higher preference share dividends reflecting additional preference shares issued in 2014 to fund the Company’s growth capital program. Additional details on items impacting Corporate earnings/(loss) include: Other Corporate loss for each period included changes in the unrealized fair value losses • on derivative financial instruments primarily related to forward foreign exchange risk management positions. Other Corporate loss for 2015 included an out-of-period adjustment to reduce deferred income • tax expense related to intercompany preferred dividends. Other Corporate loss for 2015 included the impact of a corporate tax rate change in the province • of Alberta on opening deferred income tax balances. Other Corporate loss for 2015 included employee severance costs in relation to the Company’s • enterprise-wide reduction of workforce. Other Corporate loss for 2013 included a recovery of taxes related to a historical foreign investment. • Management’s Discussion & Analysis 83
Noverco Enbridge owns an equity interest in Noverco through ownership of 38.9% of its common shares and an investment in preferred shares. Noverco is a holding company that owns approximately 71% of Gaz Metro, a natural gas distribution company operating in the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in the province of Quebec and the state of Vermont. Noverco also holds, directly and indirectly, an investment in Enbridge common shares. In 2014 and 2013, the board of directors of Noverco authorized the sale of a portion of its Enbridge common share holding to rebalance Noverco’s asset mix. In 2014, Noverco sold 1.3 million Enbridge common shares through a secondary offering. Unlike the 2013 transaction discussed below, Enbridge did not receive a dividend from Noverco for its share of the net after-tax proceeds. On May 28, 2013, Noverco sold 15 million Enbridge common shares through a secondary offering. Enbridge’s share of the net after-tax proceeds of approximately $248 million was received as dividends from Noverco on June 4, 2013 and was used to pay a portion of the Company’s quarterly dividend on September 1, 2013. A portion of this dividend did not qualify for the enhanced dividend tax credit in Canada and, accordingly, was not designated as an “eligible dividend”. The dividend was a “qualified dividend” for United States tax purposes. A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred share investments which are based on the yield of 10-year Government of Canada bonds plus a margin of 4.3% to 4.4%. Results of Operations Noverco adjusted earnings were $50 million for the year ended December 31, 2015 compared with $43 million for the year ended December 31, 2014. Noverco adjusted earnings included returns on the Company’s preferred share investments, as well as its equity earnings from Noverco’s underlying gas and power distribution investments through Gaz Metro. The increase in year-over-year adjusted earnings reflected stronger operating earnings from Gaz Metro due to a favourable United States/Canada foreign exchange rate on Gaz Metro’s United States based business and incremental earnings from new assets. Partially offsetting the higher adjusted earnings were lower preferred share dividend income based on lower yield of 10-year Government of Canada bonds. Noverco adjusted earnings decreased to $43 million for the year ended December 31, 2014 from $54 million for the year ended December 31, 2013. Excluding the impact of a small one-time gain on sale of an investment in the first quarter of 2013 and an equity earnings true-up adjustment also recognized in the first quarter of 2013, Noverco adjusted earnings were slightly higher for the year ended December 31, 2014 and reflected stronger operating earnings from Gaz Metro and higher preferred share dividend income. Other Corporate Corporate also consists of the new business development activities, general corporate investments and financing costs not allocated to the business segments. Other corporate costs include dividends on preference shares as such dividends are a deduction in determining earnings attributable to common shareholders. Results of Operations Other Corporate adjusted loss was $33 million for the year ended December 31, 2015 compared with an adjusted loss of $69 million for the year ended December 31, 2014. The decrease in adjusted loss reflected lower net Corporate segment finance costs in the first half of 2015 and lower income taxes partially offset by higher preference share dividends from an increase in the number of preference shares outstanding and higher operating and administrative costs. Other Corporate adjusted loss was $69 million for the year ended December 31, 2014 compared with an adjusted loss of $82 million for the year ended December 31, 2013. The decrease in adjusted loss reflected lower net Corporate segment finance costs and lower income taxes partially offset by higher preference share dividends from an increase in the number of preference shares outstanding and higher operating and administrative costs. 84 Enbridge Inc. 2015 Annual Report
Preference Share Issuances Since July 2011, the Company has issued 260 million preference shares for gross proceeds of approximately $6,527 million with the following characteristics. See Outstanding Share Data. Gross Initial Per Share Base Redemption and Right to ?1 ?2 2,3 3,4 Proceeds Yield Dividend Redemption Value Conversion Option Date Convert Into (Canadian dollars, unless otherwise stated) 5 Series B $500 million 4.0% $1.00 $25 June 1, 2017 Series C 5 Series D $450 million 4.0% $1.00 $25 March 1, 2018 Series E 5 Series F $500 million 4.0% $1.00 $25 June 1, 2018 Series G 5 Series H $350 million 4.0% $1.00 $25 September 1, 2018 Series I 5 Series J US$200 million 4.0% US$1.00 US$25 June 1, 2017 Series K 5 Series L US$400 million 4.0% US$1.00 US$25 September 1, 2017 Series M 5 Series N $450 million 4.0% $1.00 $25 December 1, 2018 Series O 5 Series P $400 million 4.0% $1.00 $25 March 1, 2019 Series Q 5 Series R $400 million 4.0% $1.00 $25 June 1, 2019 Series S 5 Series 1 US$400 million 4.0% US$1.00 US$25 June 1, 2018 Series 2 5 Series 3 $600 million 4.0% $1.00 $25 September 1, 2019 Series 4 5 Series 5 US$200 million 4.4% US$1.10 US$25 March 1, 2019 Series 6 5 Series 7 $250 million 4.4% $1.10 $25 March 1, 2019 Series 8 5 Series 9 $275 million 4.4% $1.10 $25 December 1, 2019 Series 10 5 Series 11 $500 million 4.4% $1.10 $25 March 1, 2020 Series 12 5 Series 13 $350 million 4.4% $1.10 $25 June 1, 2020 Series 14 5 $275 million 4.4% $1.10 $25 September 1, 2020 Series 16 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend per year, as declared by the Board of Directors of the Company. 2 The Company may at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on the Conversion Option Date and every fifth anniversary thereafter. 4 Holders will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90-day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (SeriesQ), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14) or 2.7% (Series 16)); or US$25 x (number of days in quarter/365) x (three-month United States Government treasury bill rate + 3.1% (Series K), 3.2% (SeriesM), 3.1% (Series 2) or 2.8% (Series 6)). 5 For dividends declared, see Liquidity and Capital Resources – Financing Activities. Common Share Issuance On June 24, 2014, the Company completed the issuance of 7.9 million Common Shares for gross proceeds of approximately $400 million and on July 8, 2014, issued a further 1.2 million Common Shares pursuant to the underwriters’ over-allotment option for gross proceeds of approximately $60 million. The proceeds were used to fund the Company’s growth projects, reduce short term indebtedness and for other general corporate purposes. On April 16, 2013, the Company completed the issuance of 13 million Common Shares for gross proceeds of approximately $600 million. Management’s Discussion & Analysis 85
Liquidity and Capital Resources The maintenance of financial strength and flexibility is fundamental to Enbridge’s growth strategy, particularly in light of the significant level of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside Enbridge’s control, including but not limited to financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, the Company actively manages financial plans and strategies to ensure it maintains sufficient liquidity to meet routine operating and future capital requirements. In the near term, the Company generally expects to utilize cash from operations and the issuance of debt, commercial paper and/or credit facility draws to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preference share dividends. Furthermore, the Company targets to maintain sufficient standby liquidity to bridge fund through protracted capital markets disruptions. The Company targets to maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions to enable it to fund all anticipated requirements for approximately one year without accessing the capital markets. The Company’s financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives, including utilization of its sponsored vehicles through which it can monetize assets, with the objective of diversifying funding sources and maintaining access to low cost capital. Enbridge continued to utilize its sponsored vehicles to enhance its enterprise-wide funding program. In November 2014, Enbridge finalized an agreement to transfer natural gas and diluent pipeline interests to the Fund, a transaction that provided Enbridge with approximately $1.2 billion of net funding for its growth capital program. Refer to Sponsored Investments – The Fund Group –The Fund Group Drop Down Transaction. In September 2015, with the completion of the Canadian Restructuring Plan, the Company achieved a significant milestone relating to its sponsored vehicles dropdown strategy in Canada. For further details, refer to Canadian Restructuring Plan. Following the Company’s announcement of the execution of the definitive agreement in connection with the Canadian Restructuring Plan, and ENF receiving shareholder approval thereof, as applicable, certain credit ratings of the Company were revised or affirmed as follows: DBRS Limited downgraded the Company’s issuer rating and • medium-term notes and unsecured debentures rating from A (low) to BBB (high), downgraded the Company’s commercial paper rating from R-1 (low) to R-2 (high) and downgraded the Company’s preference share rating from Pfd-2 (low) to Pfd-3 (high), all with stable trends. Moody’s Investor Services, Inc. (Moody’s) downgraded the • Company’s issuer rating and medium-term notes and unsecured debt rating from Baa1 to Baa2 and updated this rating outlook to stable and downgraded the Company’s preference share credit rating from Baa3 to Ba1 and updated this rating outlook to stable. Moody’s also affirmed the Company’s United States commercial paper rating of P-2. Standard & Poor’s Ratings Services (S&P) downgraded the • Company’s corporate credit rating and unsecured debt rating from A- to BBB+ and removed these ratings from credit watch and downgraded the Company’s preference share credit rating from P-2 to P-2 (low) and removed this rating from credit watch. S&P also affirmed the Company’s Canadian commercial paper credit rating of A-1 (low), removed this rating from credit watch and maintained a global overall A-2 short-term rating and removed this rating from credit watch. The Company’s investment grade credit ratings are a reflection of the low risk nature of the underlying assets and limited exposure to commodity prices and volume risk; its project execution track record; strong dividend coverage; and substantial standby liquidity. All ratings now have a stable outlook and the Company believes that it continues to have appropriate access to financial markets both in Canada and the United States. In the United States, under the sponsored vehicles program, the restructuring of EEP’s equity that was completed in 2014 is expected to benefit Enbridge in the longer term by lowering EEP’s cost of capital and improving its growth outlook, thus increasing incentive distributions to Enbridge and enhancing its ability to undertake drop down transactions and third party acquisitions. For further details of the Equity Restructuring, refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Equity Restructuring. Further, in January 2015, Enbridge and EEP completed the drop down of Enbridge’s 66.7% interest in the United States segment of the Alberta Clipper Pipeline to EEP. Aggregate consideration for the transaction was US$1 billion, consisting of approximately US$694 million of Class E equity units issued to Enbridge by EEP and the repayment of approximately US$306 million of indebtedness owed to Enbridge. Refer to Sponsored Investments – Enbridge Energy Partners, L.P. – Alberta Clipper Drop Down. Enbridge will continue to evaluate opportunities to generate value for its shareholders through selective dropdowns of its United States liquids pipelines assets of approximately $500 million annually to EEP depending on market conditions. 86 Enbridge Inc. 2015 Annual Report
In accordance with its funding plan, the Company completed the following public issuances in 2015: Segment Entity Type of Issuance Amount (millions of Canadian dollars, unless stated otherwise) Gas Distribution EGD Medium-term notes 570 Sponsored Investments EPI (via the Fund Group) Medium-term notes 1,000 Sponsored Investments EEP Class A common units US$294 Sponsored Investments EEP Senior notes US$1,600 Sponsored Investments ENF Common shares 700 To ensure ongoing liquidity and to mitigate the risk of capital market disruption, Enbridge maintains ready access to funds through committed bank credit facilities and it actively manages its bank funding sources to optimize pricing and other terms. The following table provides details of the Company’s committed credit facilities at December 31, 2015 and 2014. 2015 2014 Total Total 1 December 31, Maturity Facilities Draws Available Facilities (millions of Canadian dollars) 2 Liquids Pipelines 2017 28 – 28 300 Gas Distribution 2017?– 2019 1,010 603 407 1,008 2 Sponsored Investments 2017– 2020 9,224 4,089 5,135 4,531 Corporate 2017 – 2020 11,458 7,357 4,101 12,772 3 Total committed credit facilities 21,720 12,049 9,671 18,611 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group within the Sponsored Investments segment as described under the Canadian Restructuring Plan. Liquids Pipelines total facilities of $300 million as at December 31, 2014 have not been reclassified into the Sponsored Investments segment for presentation purposes. 3 On August 18, 2014, long-termprivate debt was issued for $352 million and US$1,061 million related to Southern Lights project financing. The proceeds were utilized to repay the construction credit facilities on a dollar-for-dollar basis. In addition to the committed credit facilities noted above, the Company also has $349 million (2014 – $361 million) of uncommitted demand credit facilities, of which $185 million (2014 – $80 million) was unutilized as at December 31, 2015. The Company’s net available liquidity of $10,325 million at December 31, 2015 was inclusive of $1,015 million of unrestricted cash and cash equivalents and net of bank indebtedness of $361 million as reported on the Consolidated Statements of Financial Position. The Company’s credit facility agreements include standard events of default and covenant provisions whereby accelerated repayment may be required if the Company were to default on payment or violate certain covenants. As at December 31, 2015, the Company was in compliance with all debt covenants and expects to continue to comply with such covenants. Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model have enabled Enbridge to manage its credit profile. The Company actively monitors and manages key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to total capital. As at December 31, 2015, the Company’s debt capitalization ratio was 65.5% compared with 63.1% as at December 31, 2014. The Company invests a portion of its surplus cash in short-term investment grade instruments with creditworthy counterparties. Short-term investments were $27 million as at December 31, 2015 compared with $308 million as at December 31, 2014. Surplus cash at December 31, 2015 provides additional liquidity and can be used to fund the Company’s growth projects. There are no material restrictions on the Company’s cash with the exception of cash in trust of $34 million related to cash collateral and for specific shipper commitments. Cash and cash equivalents held by EEP and the Fund Group are generally not readily accessible by Enbridge until distributions are declared and paid by these entities, which occurs quarterly for EEP and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative uses by Enbridge. Management’s Discussion & Analysis 87
Excluding current maturities of long-term debt, at December 31, 2015 and 2014 the Company had a negative working capital position of $1,227 million and $296 million, respectively, which contemplates the realization of assets and the liquidation of liabilities. In both periods, the major contributing factor is the funding of the Company’s growth capital program. Despite this negative working capital, the Company has significant net available liquidity through committed credit facilities and other sources as previously discussed, which allow the funding of liabilities as they become due. As at December 31, 2015, the net available liquidity totalled $10,325 million (2014 – $9,291 million). It is anticipated that any current maturities of long-term debt will be refinanced upon maturity. December 31, 2015 2014 (millions of Canadian dollars) 1 Cash and cash equivalents 1,049 1,308 2 Accounts receivable and other 5,437 5,745 Inventory 1,111 1,148 Bank indebtedness (361) (507) Short-term borrowings (599) (1,041) 3 Accounts payable and other (7,399) (6,524) Interest payable (324) (264) Environmental liabilities (141) (161) Working capital (1,227) (296) 1 Includes Restricted cash. 2 Includes Accounts receivable from affiliates. 3 Includes Accounts payable to affiliates. Operating Activities Cash generated from operating activities was $4,571 million for the year ended December 31, 2015 (2014 – $2,547 million; 2013 – $3,341 million). Excluding the timing effect of changes in operating assets and liabilities, the Company has delivered a growing cash flow stream over the last two years. The Company’s cash flows from operating activities in 2015 have increased by $2,024 million and $1,230 million, relative to 2014 and 2013 respectively. The cash growth delivered by operations is a reflection of the positive factors discussed in Performance Overview, which include higher throughput on the Canadian Mainline, higher volumes and tolls on EEP’s liquids business, contributions from new liquids pipeline assets placed into service in recent years and strong refinery demand for crude oil feedstock leading to more favourable tank management opportunities for Energy Services. Partially offsetting these positive factors were higher financing costs over the last two years, associated with funding of the Company’s growth program. Enbridge’s operating assets and liabilities fluctuate in the normal course due to various factors including fluctuations in commodity prices and activity levels within Energy Services and Gas Distribution, the timing of tax payments, general variations in activity levels within the Company’s businesses, as well as timing of cash receipts and payments. Cash Provided by Operating Activities (millions of Canadian dollars) 4,571 3,371 3,341 2,874 2,547 11 12 13 14 15 In 2015, the year-over-year change in cash generated from operating activities was impacted by a favourable variance of $1,035 million for changes in operating assets and liabilities, attributable primarily to a negative impact in early 2014 related to significantly higher natural gas prices combined with colder weather which lead to increased natural gas demand within the Company’s gas distribution business, resulting in the Company accumulating a significant regulatory receivable as at December 31, 2014. A significant portion of these regulatory receivables was settled in 2015. The year-over-year variance was also positively impacted by the normal course factors noted above. Partially offsetting the favourable variance was higher inventory in Energy Services, as a result of increased activity from the completion of the Seaway Pipeline Twin and Flanagan South projects in late 2014. In 2014, the year-over-year change in cash from operating activities was impacted by an unfavourable variance of $1,312 million from changes in operating assets and liabilities, mainly attributable to fluctuations in crude oil prices in the marketing and liquids businesses during the fourth quarter resulting in lower accounts payable balances, as well as increases in regulatory receivables from the gas distribution business. 88 Enbridge Inc. 2015 Annual Report
Investing Activities Cash used in investing activities was $7,933 million for the year ended December 31, 2015 (2014 – $11,891, 2013 – $9,431) and reflected the Company’s continued successful execution of its growth capital program that it has undertaken over recent years as described under Growth Projects – Commercially Secured Projects. A summary of additions to property, plant and equipment for the years ended December 31, 2015, 2014 and 2013 is set out below: Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Liquids Pipelines 2,955 5,914 4,359 Gas Distribution 858 603 533 Gas Pipelines, Processing and Energy Services 226 678 744 Sponsored Investments 3,158 3,269 2,565 Corporate 76 60 34 Total capital expenditures 7,273 10,524 8,235 The timing of growth projects’ approval, construction and in-service dates impact the timing of cash requirements. Cash used in investing activities was higher in 2014 as the Company successfully completed its significant growth projects such as Flanagan South and also made significant progress on major components of the Eastern Access Program and Edmonton to Hardisty Expansion project, which were completed in 2015. In 2015, the Company continued its growth program which included significant spending on the GTA and Southern Access Extension projects. Other notable investing activities over the last three years included the acquisition of the Company’s 24.9% interest in the 400-MW Rampion Project in the United Kingdom in 2015, acquisition of Magic Valley and Wildcat wind farms in 2014, and funding of investments in Seaway Pipeline Twin in 2014 and 2013 and Texas Express NGL System in 2013. Financing Activities Cash generated from financing activities was $2,973 million for the year ended December 31, 2015 (2014 – $9,770 million, 2013 – $5,070 million). The year-over-year reduction of cash generated from financing activities in 2015 reflected lower capital requirements as a result of a combination of timing of capital expenditures, as noted above, and increased cash flow generation from operations. In 2015, the Company increased its overall debt by $3,663 million (2014 – $9,000 million; 2013 – $3,392 million). The increase resulted from the issuance of medium-term and senior notes, net of repayments, of $2,744 million (2014 – $5,573 million; 2013 – $2,185 million) and increased credit facility and commercial paper draws, net of repayments, of $1,507 million (2014 – $2,693 million; 2013 – $1,557 million), partially offset by a reduction of $588 million in bank indebtedness and short-term borrowings (2014 – increased by $734 million; 2013 – decreased by $350 million). Capital Expenditures (millions of Canadian dollars) 10,524 8,235 7,273 13 14 15 ? Liquids Pipelines ? Gas Distribution ? Gas Pipelines, Processing and Energy Services ? Sponsored Investments ? Corporate ? Financing activities also include transactions between the Company’s Sponsored Investments and their public unitholders, also referred to as noncontrolling interests. In 2015, the Company did not issue any preference shares or common shares through public offerings directly; however, through its affiliates mainly the Fund Group and EEP, the Company raised $1,285 million of net proceeds in equity capital. These contributions in 2015 were partially offset by distributions of $794 million to noncontrolling interests. In 2014, the Company made distributions, net of contributions, of $79 million to its noncontrolling interests; whereas in 2013, the Company received contributions, net of distributions of $474 million, primarily as a result of sponsored vehicles’ equity issuances to the public. Management’s Discussion & Analysis 89
During the years ended December 31, 2014 and 2013, the Company actively issued preference shares and common shares to the public and raised net proceeds of $1,365 million and $1,428 million, respectively, from the issuance of preference shares, and $478 million and $628 million, respectively, from the issuance of common shares. With higher preference shares and common shares outstanding along with an increase in the common share dividend rate, the amount of dividends paid by the Company has increased over the last two years. Dividend Reinvestment and Share Purchase Plan Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends. For the year ended December 31, 2015, dividends declared were $1,596 million (2014 – $1,177 million), of which $950 million (2014 – $749 million) were paid in cash and reflected in financing activities. The remaining $646 million (2014 – $428 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the years ended December 31, 2015 and 2014, 40.5% and 36.4%, respectively, of total dividends declared were reinvested. On December 2, 2015, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2016 to shareholders of record on February 16, 2016. Common Shares $0.53000 Preference Shares, Series A $0.34375 Preference Shares, Series B $0.25000 Preference Shares, Series D $0.25000 Preference Shares, Series F $0.25000 Preference Shares, Series H $0.25000 Preference Shares, Series J US$0.25000 Preference Shares, Series L US$0.25000 Preference Shares, Series N $0.25000 Preference Shares, Series P $0.25000 Preference Shares, Series R $0.25000 Preference Shares, Series 1 US$0.25000 Preference Shares, Series 3 $0.25000 Preference Shares, Series 5 US$0.27500 Preference Shares, Series 7 $0.27500 Preference Shares, Series 9 $0.27500 Preference Shares, Series 11 $0.27500 Preference Shares, Series 13 $0.27500 Preference Shares, Series 15 $0.27500 Contractual Obligations Payments due under contractual obligations over the next five years and thereafter are as follows: Less than After Total 1 year 1 – 3 years 3 – 5 years 5years (millions of Canadian dollars) 1 Long-term debt 30,224 1,987 3,836 4,724 19,677 Capital and operating leases 1,102 123 189 133 657 Long-term contracts 14,445 5,505 3,200 2,187 3,553 2 Pension obligations 118 118 – – – Total contractual obligations 45,889 7,733 7,225 7,044 23,887 1 Represents debenture and term note maturities and excludes interest obligations. Changes to the planned funding requirements are dependent on the terms of any debt refinancing agreements. 2 Assumes only required payments will be made into the pension plans in 2016. Contributions are made in accordance with independent actuarial valuations as at December 31, 2015. Contributions, including discretionary payments, may vary pending future benefit design and asset performance. 90 Enbridge Inc. 2015 Annual Report
Capital Expenditure Commitments Included within Long-term contracts in the table above are contracts that the Company has signed for the purchase of services, pipe and other materials totalling $3,993 million which are expected to be paid over the next five years. Tax Matters Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review. Other Litigation The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, Management believes that the resolution of such actions and proceedings will not have a material impact on the Company’s consolidated financial position or results of operations. ?1 Outstanding Share Data Preference Shares Redemption and Right to 2,3 ?3 Number Conversion Option Date Convert Into Preference Shares, Series A 5,000,000 – – Preference Shares, Series B 20,000,000 June 1, 2017 Series C Preference Shares, Series D 18,000,000 March 1, 2018 Series E Preference Shares, Series F 20,000,000 June 1, 2018 Series G Preference Shares, Series H 14,000,000 September 1, 2018 Series I Preference Shares, Series J 8,000,000 June 1, 2017 Series K Preference Shares, Series L 16,000,000 September 1, 2017 Series M Preference Shares, Series N 18,000,000 December 1, 2018 Series O Preference Shares, Series P 16,000,000 March 1, 2019 Series Q Preference Shares, Series R 16,000,000 June 1, 2019 Series S Preference Shares, Series 1 16,000,000 June 1, 2018 Series 2 Preference Shares, Series 3 24,000,000 September 1, 2019 Series 4 Preference Shares, Series 5 8,000,000 March 1, 2019 Series 6 Preference Shares, Series 7 10,000,000 March 1, 2019 Series 8 Preference Shares, Series 9 11,000,000 December 1, 2019 Series 10 Preference Shares, Series 11 20,000,000 March 1, 2020 Series 12 Preference Shares, Series 13 14,000,000 June 1, 2020 Series 14 Preference Shares, Series 15 11,000,000 September 1, 2020 Series 16 Common Shares Number Common Shares–issued and outstanding (voting equity shares) 867,797,356 Stock Options–issuedandoutstanding (20,413,827 vested) 35,794,798 1 Outstanding share data information is provided as at February 17, 2016. 2 All preference shares are non-voting equity shares. Preference Shares, Series Amay be redeemed any time at the Company’s option. For all other series of Preference Shares, the Company may, at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. Management’s Discussion & Analysis 91
Quarterly Financial Information 2015 Q1 Q2 Q3 Q4 Total (millions of Canadian dollars, except for per share amounts) Revenues 7,929 8,631 8,320 8,914 33,794 Earnings/(loss) attributable to common shareholders (383) 577 (609) 378 (37) Earnings/(loss)per common share (0.46) 0.68 (0.72) 0.44 (0.04) Diluted earnings/(loss) per common share (0.46) 0.67 (0.72) 0.44 (0.04) Dividends paid per common share 0.465 0.465 0.465 0.465 1.86 EGD – warmer/(colder) than normal weather (33) 6 – 16 (11) Changes in unrealized derivative fair value (gains)/loss 977 (296) 654 45 1,380 2014 Q1 Q2 Q3 Q4 Total (millions of Canadian dollars, except for per share amounts) Revenues 10,521 10,026 8,297 8,797 37,641 Earnings/(loss) attributable to common shareholders 390 756 (80) 88 1,154 Earnings/(loss)per common share 0.48 0.92 (0.10) 0.11 1.39 Diluted earnings/(loss) per common share 0.47 0.91 (0.10) 0.10 1.37 Dividends paid per common share 0.3500 0.3500 0.3500 0.3500 1.40 EGD – warmer/(colder) than normal weather (33) (4) 2 (1) (36) Changes in unrealized derivative fair value (gains)/loss 190 (430) 396 164 320 Several factors impact comparability of the Company’s financial results on a quarterly basis, including, but not limited to, seasonality in the Company’s gas distribution businesses, fluctuations in market prices such as foreign exchange rates and commodity prices, disposals of investments or assets and the timing of in-service dates of new projects. A significant part of the Company’s revenues are generated from its energy services operations. Revenues from these operations depend on activity levels, which vary from year to year depending on market conditions and commodity prices. Commodity prices do not directly impact earnings since these earnings reflect a margin or percentage of revenues that depends more on differences in commodity prices between locations and points in time than on the absolute level of prices. EGD and the Company’s other gas distribution businesses are subject to seasonal demand. A significant portion of gas distribution customers use natural gas for space heating; therefore, volumes delivered and resulting revenues and earnings typically increase during the winter months of the first and fourth quarters of any given year. Revenues generated by EGD and other gas distribution businesses also vary from quarter-to-quarter with fluctuations in the price of natural gas, although earnings remain neutral due to the flow-through nature of these costs. The Company actively manages its exposure to market risks including, but not limited to, commodity prices, interest rates and foreign exchange rates. To the extent derivative instruments used to manage these risks are non-qualifying for the purposes of applying hedge accounting, changes in unrealized fair value gains and losses on these instruments will impact earnings. In addition to the impacts of weather in EGD’s franchise area and changes in unrealized gains and losses outlined above, significant items impacting the consolidated quarterly earnings are noted below: Included in the fourth quarter of 2015 were employee severance costs in relation to the • Company’s enterprise-wide reduction of workforce, with a net charge of $25 million to earnings across business segments. Included in the fourth quarter of 2015 was an asset impairment charge of US$63 million ($11 million • after-tax attributable to Enbridge) related to EEP’s Berthold rail facility due to the inability to renew committed shipper agreements beyond 2016 or secure sufficient spot volume. Included in the third quarter of 2015 were impacts from the transfer of assets between entities • under common control of Enbridge in connection with the Canadian Restructuring Plan, resulting in a $247 million loss on the de-designation of interest rate hedges, an $88 million write-off of a regulatory asset in respect of taxes and $16 million of transaction costs. 92 Enbridge Inc. 2015 Annual Report
Included in the third quarter of 2015 was an after-tax gain • of $44 million on the disposal of non-core assets within the Liquids Pipelines segment. Included in the second quarter of 2015 was a goodwill • impairment charge of $440 million ($167 million after-tax attributable to Enbridge) related to EEP’s natural gas and NGL businesses due to a prolonged decline in commodity prices which reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL systems. Included in the second quarter of 2015 and fourth quarter of • 2014 were the tax impact of asset transfers between entities under common control of Enbridge. The intercompany gains realized by the selling entities have been eliminated from the Company’s consolidated financial statements. However, as the transaction involved sale of partnership units, the tax consequences have remained in consolidated earnings and resulted in a charge of $39 million and $157 million, respectively. Included in earnings are after-tax gains on the disposal of • non-core Offshore assets. The Company recognized gains of $4 million in the second quarter of 2015 and $43 million and $14 million in first and fourth quarters of 2014, respectively. Earnings in the first quarter of 2014 also included a $14 million after-tax gain on the sale of an Alternative and Emerging Technologies investment within the Corporate segment. Included in earnings is the Company’s share of after-tax leak • remediation costs associated with the Line 6B crude oil release. Remediation costs of $5 million and $12 million were recognized in the second and third quarters of 2014. In the fourth quarter of 2014, the Company recognized an out-of-period adjustment of $5 million to reduce Enbridge’s share of leak remediation costs recognized in the third quarter of 2014. Included in earnings are after-tax costs of $6 million in the • second quarter of 2015 and $4 million in the third quarter of 2014, in connection with the Line 37 crude oil release which occurred in June 2013. Earnings also reflected insurance recoveries associated with the Line 37 crude oil release of $9 million recognized in the first quarter of 2015 and $4 million recognized in each of the second quarter and fourth quarter of 2014, respectively. In the fourth quarter of 2015, earnings reflected the Company’s share of after-tax insurance recoveries of $13 million under the Fund Group within Sponsored Investments. Finally, the Company is in the midst of a substantial growth capital program and the timing of construction and completion of growth projects may impact the comparability of quarterly results. The Company’s capital expansion initiatives, including construction commencement and in-service dates, are described under Growth Projects – Commercially Secured Projects and Other Announced Projects Under Development. Related Party Transactions Other than the drop down transactions between Enbridge and its sponsored vehicles, including the Canadian Restructuring Plan, all related party transactions are conducted in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Vector, a joint venture, contracts the services of Enbridge to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, were $7 million for the year ended December 31, 2015 (2014 – $7 million; 2013 – $6 million). Certain wholly-owned subsidiaries within the Company’s Gas Distribution, Gas Pipelines, Processing and Energy Services and Sponsored Investments segments have committed and uncommitted transportation arrangements with several joint venture affiliates that are accounted for using the equity method. Total amounts charged to the Company for transportation services for the year ended December 31, 2015 were $332 million (2014 – $256 million; 2013 – $222 million). Certain wholly-owned subsidiaries within Gas Distribution and Gas Pipelines, Processing and Energy Services made natural gas and NGL purchases of $228 million (2014 – $315 million; 2013 –$99 million) from several joint venture affiliates during the year ended December 31, 2015. Natural gas sales of $5 million (2014 – $58 million; 2013 – $10 million) were made by certain wholly-owned subsidiaries within Gas Pipelines, Processing and Energy Services to several joint venture affiliates during the year ended December 31, 2015. Long-Term Notes Receivable from Affiliates Amounts receivable from affiliates include a series of loans to Vector and other affiliates totalling $149 million and $3 million, respectively (2014 – $183 million and nil, respectively), which require quarterly interest payments at annual interest rates ranging from 4% to 12%. These amounts are included in Deferred amounts and other assets. Management’s Discussion & Analysis 93
Risk Management and Financial Instruments Market Risk The Company’s earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price (collectively, market risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which the Company is exposed and the risk management instruments used to mitigate them. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk The Company generates certain revenues, incurs expenses and holds a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, the Company’s earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. The Company has implemented a policy whereby, at a minimum, it hedges a level of foreign currency denominated earnings exposures over a five year forecast horizon. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. The Company hedges certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt. Interest Rate Risk The Company’s earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense through 2019 via execution of floating to fixed interest rate swaps with an average swap rate of 2.0%. The Company’s earnings and cash flows are also exposed to variability in longer-term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances through 2019 via execution of floating to fixed interest rate swaps with an average swap rate of 3.4%. The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt within its Board of Directors approved policy limit of a maximum of 25% floating rate debt as a percentage of total debt outstanding. The Company primarily uses qualifying derivative instruments to manage interest rate risk. Commodity Price Risk The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of its ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. The Company employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk. Equity Price Risk Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted stock units. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk. 94 Enbridge Inc. 2015 Annual Report
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income The following table presents the effect of derivative instruments on the Company’s consolidated earnings and consolidated comprehensive income. Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Amount of unrealized gains/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts 77 856 Interest rate contracts (275) (1,086) 814 Commodity contracts 9 50 (9) Other contracts (47) 13 (2) Net investment hedges Foreign exchange contracts (248) (113) (81) (484) (1,128) 778 Amount of gains/(loss) reclassified from Accumulated other comprehensive income (AOCI) to earnings (effective portion) 1 Foreign exchange contracts 9 8 (8) 2 Interest rate contracts 128 101 107 3 Commodity contracts (46) 41 4 Other contracts 28 (7) – 119 106 100 De-designation of qualifying hedges in connection with the Canadian Restructuring Plan 2 Interest rate contracts 338 –– 338 –– Amount of gains/(loss) reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) 2 Interest rate contracts 21 216 51 3 Commodity contracts 5 (6) (3) 26 210 48 Amount of gains/(loss) from non-qualifying derivatives included in earnings 1 Foreign exchange contracts (2,187) (936) (738) 2,5 Interest rate contracts (363) 4(10) 3 Commodity contracts 199 1,031 (496) 4 Other contracts (22) 7(3) (2,373) 106 (1,247) 1 Reported within Transportation and other services revenues and Other expense in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues, Commodity revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 The amounts above include $338 million for the year ended December 31, 2015 relating to the de-designation of qualifying hedges in connection with the Canadian Restructuring Plan. Liquidity Risk Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees, as they become due. In order to manage this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. The Company maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. However, leading up to the closure of the Canadian Restructuring Plan, the Company did not access the public markets as regularly as it had in previous years. However, once the Canadian Restructuring Plan was closed, Enbridge again began to access the public debt and equity markets in normal course. The Company is in compliance with all the terms and conditions of its committed credit facilities as at December 31, 2015. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities. Management’s Discussion & Analysis 95
Credit Risk Entering into derivative financial instruments may result in exposure to credit risk. Credit risk arises from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, the Company enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements. The Company generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with the counterparties in these particular circumstances. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Gas Distribution, credit risk is mitigated by the utilities’ large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classifies and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value. Fair Value Measurements The Company uses the most observable inputs available to estimate the fair value of its derivatives. When possible, the Company estimates the fair value of its derivatives based on quoted market prices. If quoted market prices are not available, the Company uses estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, the Company uses standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, the Company uses observable market prices (interest rates, foreign exchange rates, commodity prices and share prices, as applicable) and volatility as primary inputs to these valuation techniques. Finally, the Company considers its own credit default swap spread, as well as the credit default swap spreads associated with its counterparties, in its estimation of fair value. General Business Risks Strategic and Commercial Risks Public Opinion Public opinion or reputation risk is the risk of negative impacts on the Company’s business, operations or financial condition resulting from changes in the Company’s reputation with stakeholders, special interest groups, political leadership, the media or other entities. Public opinion may be influenced by certain media and special interest groups’ negative portrayal of the industry in which Enbridge operates as well as their opposition to development projects, such as Northern Gateway. Potential impacts of a negative public opinion may include loss of business, delays in project execution, legal action, increased regulatory oversight or delays in regulatory approval and higher costs. Reputation risk often arises as a consequence of some other risk event, such as in connection with operational, regulatory or legal risks. Therefore, reputation risk cannot be managed in isolation from other risks. The Company manages reputation risk by: having health, safety and environment management systems in • place, as well as policies, programs and practices for conducting safe and environmentally sound operations with an emphasis on the prevention of any incidents; having formal risk management policies, procedures and • systems in place to identify, assess and mitigate risks to the Company; operating to the highest ethical standards, with integrity, • honesty and transparency, and maintaining positive relationships with customers, investors, employees, partners, regulators and other stakeholders; building awareness and understanding of the role energy • and Enbridge play in people’s lives in order to promote better understanding of the Company and its businesses; having strong corporate governance practices, including a • Statement on Business Conduct, which requires all employees to certify their compliance with Company policy on an annual basis, and whistleblower procedures, which allow employees to report suspected ethical concerns on a confidential and anonymous basis; and pursuing socially responsible operations as a longer-term • corporate strategy (implemented through the Company’s CSR Policy, Climate Change Policy and Aboriginal and Native American Policy). The Company’s actions noted above are the key mitigation actions against negative public opinion; however, the public opinion risk cannot be mitigated solely by the Company’s individual actions. The Company actively works with other stakeholders in the industry to collaborate and work closely with government and Aboriginal communities to enhance the public opinion of the Company, as well as the industry in which it operates. Unless otherwise specifically stated, none of the content of the policies or initiatives described above are incorporated by reference herein. 96 Enbridge Inc. 2015 Annual Report
Project Execution As the Company continues to execute on a large slate of commercially secured growth projects, it continues to focus on completing projects safely, on-time and on-budget. The Company’s ability to successfully execute the development of its organic growth projects may be influenced by capital constraints, third-party opposition, changes in shipper support over time, delays in or changes to government and regulatory approvals, cost escalations, construction delays, inadequate resources, in-service delays and increasing complexity of projects (collectively, Execution Risk). Early stage project risks include right-of-way procurement, special interest group opposition, Crown consultation and environmental and regulatory permitting. Cost escalations or missed in-service dates on future projects may impact future earnings and cash flows and may hinder the Company’s ability to secure future projects. Construction delays due to regulatory delays, third-party opposition, contractor or supplier non-performance and weather conditions may impact project development. The Company strives to be an industry leader in project execution and through its Major Projects group it seeks to mitigate project Execution Risk. Major Projects is centralized and has a clearly defined governance structure and process for all major projects, with dedicated resources organized to lead and execute each major project. Capital constraints and cost escalation risks are mitigated through structuring of commercial agreements, typically where shippers retain complete or a share of capital cost excess. Detailed cost tracking and centralized purchasing is used on all major projects to facilitate optimum pricing and service terms. Strategic relationships have been developed with suppliers and contractors and those selected are chosen based on the Company’s strict adherence to safety including robust safety standards embedded in contracts with suppliers. The Company has assessed work volumes for the next several years across its major projects to optimize the expected costs, supply of services, material and labour to execute the projects. Underpinning this approach is Major Project’s Project Lifecycle Gating Control tool which helps to ensure schedule, cost, safety and quality objectives are on track and met for each stage of a project’s development and construction. Consultations with regulators are held in-advance of project construction to enhance understanding of project rationale and ensure applications are compliant and robust, while at all times maintaining a strong focus on integrity and public safety. The Company also actively involves its legal and regulatory teams to work closely with Major Projects to engage in open dialogue with government agencies, regulators, land owners, Aboriginal groups and special interest groups to identify and develop appropriate responses to their concerns regarding the Company’s projects. Operational and Economic Regulation, Permits and Approvals Many of the Company’s operations are regulated and are subject to both operational and economic regulatory risk. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States has changed significantly in past years and there is no assurance that further substantial changes will not occur. Operational regulation risks relate to failing to comply with applicable operational rules and regulations from government organizations and could result in fines, operating restrictions or shutdown of assets or an overall increase in operating and compliance costs. Regulatory scrutiny over the Company’s assets has the potential to increase operating costs or limit future projects. Potential regulatory changes could have an impact on the Company’s future earnings and the cost related to the construction of new projects. The Company believes operational regulation risk is mitigated by active monitoring and consulting on potential regulatory requirement changes with the respective regulators or through industry associations. The Company also develops robust response plans to regulatory changes or enforcement actions. While the Company believes the safe and reliable operation of its assets and adherence to existing regulations is the best approach to managing operational regulatory risk, the potential remains for regulators to make unilateral decisions that could have a financial impact on the Company. The Company also faces economic regulation, permits and approvals risk, which broadly defined, is the risk that regulators or other government entities change or reject proposed or existing commercial arrangements including permits and regulatory approvals for new projects. The changing or rejecting of commercial arrangements, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could have an adverse effect on the Company’s revenues and earnings. Increasing regulatory scrutiny and resulting delays in regulatory permits and approvals could result in cost escalations, construction delays and in-service delays which also negatively impact the Company’s operations. The Company believes that economic regulatory risk is reduced through the negotiation of long-term agreements with shippers that govern the majority of its operations. The Company also involves its legal and regulatory teams in the review of new projects to ensure compliance with applicable regulations as well as in the establishment of tariffs and tolls for these assets. Enbridge retains dedicated professional staff and maintains strong relationships with customers, intervenors and regulators to help minimize economic regulation risk. However, despite the efforts of the Company to mitigate economic regulation risk, there remains a risk that a regulator could overturn long-term agreements between the Company and shippers or deny the approval and permits for new projects. Planning and Investment Analysis The Company evaluates expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, financial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, change in cost estimates, project scoping and risk assessment could result in a loss in profits for the Company. Large scale acquisitions may involve significant price and integration risk. The planning and investment analysis process involves all levels of management and Board of Directors’ review to ensure alignment across the Company. A centralized corporate development group rigorously evaluates all major investment proposals with Management’s Discussion & Analysis 97
consistent due diligence processes, including a thorough review of the asset quality, systems and financial performance of the assets being assessed. Operational Risks Environmental Incident An environmental incident could have lasting reputational impacts to Enbridge and could impact its ability to work with various stakeholders. In addition to the cost of remediation activities (to the extent not covered by insurance), environmental incidents may lead to an increased cost of operating and insuring the Company’s assets, thereby negatively impacting earnings. The Company mitigates risk of environmental incidents through its ORM Plan, which broadly aims to position Enbridge as the industry leader for system integrity, environmental and safety programs. Mitigation efforts continue to focus on efforts to reduce the likelihood of an environmental incident. Under the umbrella of the ORM Plan the Company has continued its maintenance, excavation and repair program which is supported by operating and capital budgets for pipeline integrity. The Company’s $7.5 billion L3R Program, the largest project in the Company’s history, is a further commitment by the Company to its key strategic priority of safety and operational reliability. Once it is completed, the L3R Program will provide a major enhancement to Enbridge’s mainline system by replacing most segments of the Line 3 pipeline with the latest high-strength steel and coating. Although the Company believes its integrated management system, plans and processes mitigate the risk of environmental incidents, there remains a chance that an environmental incident could occur. The ORM Plan also seeks to mitigate the severity of a potential environmental incident through continued process improvements and enhancements in leak detection processes and alarm analysis procedures. The Company has also invested significant resources to enhance its emergency response plans, operator training and landowner education programs to address any potential environmental incident. The Company maintains comprehensive insurance coverage for its subsidiaries and affiliates that it renews annually. The insurance program includes coverage for commercial liability that is considered customary for its industry and includes coverage for environmental incidents. The total insurance coverage will be allocated on an equitable basis in the unlikely event multiple insurable incidents exceeding the Company’s coverage limits are experienced by Enbridge and two Enbridge subsidiaries covered by the same policy within the same insurance period. Public, Worker and Contractor Safety Several of the Company’s pipeline systems run adjacent to populated areas and a major incident could result in injury to members of the public. A public safety incident could result in reputational damage to the Company, material repair costs or increased costs of operating and insuring the Company’s assets. In addition, given the natural hazards inherent in Enbridge’s operations, its workers and contractors are subject to personal safety risks. Safety and operational reliability are the most important priorities at Enbridge. Enbridge’s mitigation efforts to reduce the likelihood and severity of a public safety incident are executed primarily through its ORM Plan and emergency response preparedness, as described above in Environmental Incident. The Company also actively engages stakeholders through public safety awareness activities to ensure the public is aware of potential hazards and understands the appropriate actions to take in the event of an emergency. Enbridge also actively engages first responders through education programs that endeavour to equip first responders with the skills and tools to safely and effectively respond to a potential incident. Finally, Enbridge believes in a safety culture where safety incidents are not tolerated by employees and contractors and has established a target of zero incidents. For employees, safety objectives have been incorporated across all levels of the Company and are included as part of an employee’s compensation measures. Contractors are chosen following a rigorous selection process that includes a strict adherence to Enbridge’s safety culture. Information Technology Security or Systems Incident The Company’s infrastructure, applications and data are becoming more integrated, creating an increased risk that failure in one system could lead to a failure of another system. There is also increasing industry-wide cyber-attacking activity targeting industrial control systems and intellectual property. A successful cyber-attack could lead to unavailability, disruption or loss of key functionalities within the Company’s industrial control systems which could impact pipeline operations and potentially result in an environmental or public safety incident. A successful cyber-attack could also lead to a large scale data breach resulting in unauthorized disclosure, corruption or loss of sensitive company or customer information which could have lasting reputational impacts to Enbridge and could impact its ability to work with various stakeholders. The Company has implemented a comprehensive security strategy that includes a security policy and standards framework, defined governance and oversight, layered access controls, continuous monitoring, infrastructure and network security and threat detection and incident response through a security operations centre. The Company’s information technology security operations are consolidated under one leadership structure to increase consistency and compliance with the Company’s security requirements across business segments. Service Interruption Incident A service interruption due to a major power disruption or curtailment on commodity supply could have a significant impact on the Company’s ability to operate its assets and negatively impact future earnings, relationships with stakeholders and the Company’s reputation. Specifically, for Gas Distribution, any prolonged interruptions would ultimately impact gas distribution customers. Service interruptions that impact the Company’s crude oil transportation services can negatively impact shippers’ operations and earnings as they are dependent on Enbridge services to move their product to market or fulfill their own contractual arrangements. The Company mitigates service interruption risk through its diversified sources of supply, storage withdrawal flexibility, backup power systems, critical parts inventory and redundancies for critical 98 Enbridge Inc. 2015 Annual Report
equipment. Specifically for Gas Distribution, the GTA project, which is expected to be completed by the end of the first quarter of 2016, will be a key mitigation as the project is expected to provide significant diversification of gas supply to EGD’s distribution network and will further reduce the likelihood of a service interruption incident. Business Environment Risks Aboriginal Relations Canadian judicial decisions have recognized that Aboriginal rights and treaty rights exist in proximity to the Company’s operations and future project developments. The courts have also confirmed that the Crown has a duty to consult with Aboriginal people when its decisions or actions may adversely affect Aboriginal rights and interests or treaty rights. Crown consultation has the potential to delay regulatory approval processes and construction, which may affect project economics. In some cases, respecting Aboriginal rights may mean regulatory approval is denied or the conditions in the approval make a project economically challenging. Given this environment and the breadth of relationships across the Company’s geographic span, Enbridge has implemented an Aboriginal and Native American Policy. This policy promotes the achievement of participative and mutually beneficial relationships with Aboriginal and Native American groups affected by the Company’s projects and operations. Specifically, the policy sets out principles governing the Company’s relationships with Aboriginal and Native American people and makes commitments to work with Aboriginal people and Native Americans so they may realize benefits from the Company’s projects and operations. Notwithstanding the Company’s efforts to this end, the issues are complex and the impact of Aboriginal and Native American relations on Enbridge’s operations and development initiatives is uncertain. Unless otherwise specifically stated, none of the content of this policy is incorporated by reference herein. Special Interest Groups including Non-Governmental Organizations The Company is exposed to the risk of higher costs, delays or even project cancellations due to increasing pressure on governments and regulators by special interest groups, including non-governmental organizations. Recent judicial decisions have increased the ability of special interest groups to make claims and oppose projects in regulatory and legal forums. In addition to issues raised by groups focused on particular project impacts, the Company and others in the energy and pipeline businesses are facing opposition from organizations opposed to oil sands development and shipment of production from oil sands regions. The Company works proactively with special interest groups and non-governmental organizations to identify and develop appropriate responses to their concerns regarding its projects. The Company is investing significant resources in these areas. Its CSR program also reports on the Company’s responsiveness to environmental and community issues. Refer to Enbridge’s annual CSR Report, available online at csr.enbridge.com for further details regarding the CSR program. Unless otherwise specifically stated, none of the information contained on, or connected to, the Enbridge website is incorporated by reference in, or otherwise part of this MD&A. Critical Accounting Estimates The following critical accounting estimates discussed below have an impact across the various segments of the Company. Depreciation Depreciation of property, plant and equipment, the Company’s largest asset with a net book value at December 31, 2015 of $64,434 million (2014 – $53,830 million), or 76.1% of total assets, is generally provided on a straight-line basis over the estimated service lives of the assets commencing when the asset is placed in service. When it is determined that the estimated service life of an asset no longer reflects the expected remaining period of benefit, prospective changes are made to the estimated service life. Estimates of useful lives are based on third party engineering studies, experience and/or industry practice. There are a number of assumptions inherent in estimating the service lives of the Company’s assets including the level of development, exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by the Company’s pipelines as well as the demand for crude oil and natural gas and the integrity of the Company’s systems. Changes in these assumptions could result in adjustments to the estimated service lives, which could result in material changes to depreciation expense in future periods in any of the Company’s business segments. For certain rate-regulated operations, depreciation rates are approved by the regulator and the regulator may require periodic studies or technical updates on useful lives which may change depreciation rates. Asset Impairment The Company evaluates the recoverability of its property, plant and equipment when events or circumstances such as economic obsolescence, business climate, legal or regulatory changes, or other factors indicate it may not recover the carrying amount of the assets. The Company continually monitors its businesses, the market and business environments to identify indicators that could suggest an asset may not be recoverable. An impairment loss is recognized when the carrying amount of the asset exceeds its fair value as determined by quoted market prices in active markets or present value techniques. The determination of the fair value using present value techniques requires the use of projections and assumptions regarding future cash flows and weighted average cost of capital. Any changes to these projections and assumptions could result in revisions to the evaluation of the recoverability of the property, plant and equipment and the recognition of an impairment loss in the Consolidated Statements of Earnings. The Company also tests goodwill for impairment annually or more frequently if events or changes in circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value. For the purposes of impairment testing, reporting units are identified as business operations within an operating segment. The Company has the option to first assess qualitative factors to determine whether it is necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test is performed, the first step involves determining the fair value of the Company’s reporting units inclusive of goodwill and comparing those values to the carrying value of each reporting unit. If the carrying Management’s Discussion & Analysis 99
value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured as the excess of the carrying amount of the reporting unit’s allocated goodwill over the implied fair value of the goodwill based on the fair value of the reporting unit’s assets and liabilities. Regulatory Assets and Liabilities Certain of the Company’s businesses are subject to regulation by various authorities, including but not limited to, the NEB, the FERC, the AER and the OEB. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non-rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative (LMCI). Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if the Company identifies an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions or expected future actions of the regulator. To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, the Company would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. As at December 31, 2015, the Company’s significant regulatory assets totalled $1,782 million (2014 – $2,174 million) and significant regulatory liabilities totalled $869 million (2014 – $962 million). Postretirement Benefits The Company maintains pension plans, which provide defined benefit and/or defined contribution pension benefits and OPEB to eligible retirees. Pension costs and obligations for the defined benefit pension plans are determined using the universal method. This method involves complex actuarial calculations using several assumptions including discount rates, which were determined by referring to high-quality long-term corporate bonds with maturities that approximate the timing of future payments the Company anticipates making under each of the respective plans, expected rates of return on plan assets, health-care cost trend rates, projected salary increases, retirement age, mortality and termination rates. These assumptions are determined by management and are reviewed annually by the Company’s actuaries. Actual results that differ from assumptions are amortized over future periods and therefore could materially affect the expense recognized and the recorded obligation in future periods. The shortfall from the expected return on plan assets was $62 million for the year ended December 31, 2015 (2014 – $58 million excess) as disclosed in Note 26, Retirement and Postretirement Benefits, to the 2015 Annual Consolidated Financial Statements. The difference between the actual and expected return on plan assets is amortized over the remaining service period of the active employees. The following sensitivity analysis identifies the impact on the December 31, 2015 Consolidated Financial Statements of a 0.5% change in key pension and OPEB assumptions. Pension Benefits OPEB Obligation Expense Obligation Expense (millions of Canadian dollars) Decrease in discount rate 209 31 24 1 Decrease inexpected return on assets –10 – 1 Decrease in rate of salary increase (43) (14) – – 100 Enbridge Inc. 2015 Annual Report
Contingent Liabilities Provisions for claims filed against the Company are determined on a case-by-case basis. Case estimates are reviewed on a regular basis and are updated as new information is received. The process of evaluating claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the final determination of which could have a material impact on the financial results of the Company and certain of the Company’s subsidiaries and investments are detailed in Note 31, Commitments and Contingencies, of the 2015 Annual Consolidated Financial Statements. In addition, any unasserted claims that later may become evident could have a material impact on the financial results of the Company and certain of the Company’s subsidiaries and investments. Asset Retirement Obligations Asset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. The Company’s estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of the Company’s assets, there is insufficient data or information to reasonably determine the timing of settlement for estimating the fair value of the ARO. In these cases, the ARO cost is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset. In 2009, the NEB issued a decision related to the LMCI, which required holders of an authorization to operate a pipeline under the NEB Act to file a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The NEB’s decision stated that while pipeline companies are ultimately responsible for the full costs of abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable from the users of the pipeline upon approval by the NEB. Following the NEB’s final approval of the collection mechanism and the set-aside mechanism for LMCI, the Company began collecting and setting aside funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trust in accordance with the NEB decision. The funds collected from shippers are reported within Transportation and other services revenues and Restricted long-term investments. Concurrently, the Company reflects the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities. Changes in Accounting Policies Adoption of Accounting Policy Principles of Consolidation and Noncontrolling Interests As a result of the Canadian Restructuring Plan, ECT, a subsidiary of the Company, determines its equity investment earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the HLBV method to its equity method investments where cash distributions, including both preference and residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that ECT would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s share of the earnings or losses from the equity investment for the period. While ECT and EIPLP are both consolidated in the financial statements of Enbridge, the use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of Earnings. The Company continues to recognize Redeemable noncontrolling interests on its Consolidated Statements of Financial Position at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares. Adoption of New Standards Extraordinary and Unusual Items Effective January 1, 2015, the Company retrospectively adopted ASU 2015-01 which eliminates the concept of extraordinary items from U.S. GAAP. Entities will no longer be required to separately classify and present extraordinary items in the Consolidated Statements of Earnings. There was no material impact to the Company’s consolidated financial statements as a result of adopting this update. Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity Effective January 1, 2015, the Company prospectively adopted Accounting Standards Update (ASU) 2014-08 which changes the criteria and disclosures for reporting discontinued operations. The revised criteria will in general, result in fewer transactions being categorized as discontinued operations. There was no material impact to the consolidated financial statements as a result of adopting this update. Future Accounting Policy Changes Recognition and Measurement of Financial Assets and Liabilities ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation, and disclosure of financial assets and liabilities. The amendments Management’s Discussion & Analysis 101
revise accounting related to the classification and measurement of investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value, and the disclosure requirements associated with the fair value of financial instruments. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017 and is to be applied by means of a cumulative-effect adjustment to the Statement of Financial Position as of the beginning of the fiscal year of adoption, with amendments related to equity securities without readily determinable fair values to be applied prospectively. Classification of Deferred Taxes on the Statement of Financial Position ASU 2015-17 was issued in November 2015 with the intent to simplify the presentation of deferred income taxes. The amendments require that deferred tax liabilities and assets be classified as noncurrent in a Statement of Financial Position. The accounting update is effective for fiscal years beginning after December 15, 2016 and is to be applied on a prospective or retrospective basis. The Company is currently assessing the impact of the new standard on its consolidated financial statements. Early application is permitted for all entities as of the beginning of an interim or annual reporting period. Effective January 1, 2016, the Company will elect to early adopt ASU 2015-17. Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations ASU 2015-16 was issued in September 2015 with the intent to simplify the accounting for measurement-period adjustments in business combinations. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The accounting update is effective for fiscal years beginning after December 15, 2015 and is to be applied on a prospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements. Simplifying the Measurement of Inventory ASU 2015-11 was issued in July 2015 with the intent to simplify the measurement of inventory. The new standard requires inventory to be measured at the lower of cost and net realizable value and is applicable to all inventory, with the exception of inventory measured using last-in, first-out or the retail inventory method. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The new standard is effective for annual and interim reporting periods beginning after December 15, 2016 and is to be applied on a prospective basis. Measurement Date of Defined Benefit Obligation and Plan Assets ASU 2015-04 was issued in April 2015 with the intent to simplify the fair value measurement of defined benefit plan assets and obligations. For entities with a fiscal year end that does not coincide with a month end, the new standard permits an entity to measure its defined benefit plan assets and obligations using the month end that is closest to the entity’s fiscal year end. In addition, where there are significant events in an interim period that would trigger a re-measurement of the plan assets and obligations, an entity is also permitted to re-measure such assets and obligations using the month end that is closest to the date of the significant event. The accounting update is effective for financial statements issued for fiscal years beginning after December 15, 2015 and is to be applied on a prospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements. Simplifying the Presentation of Debt Issuance Costs ASU 2015-03 was issued in April 2015 with the intent to simplify the presentation of debt issuance costs. The new standard requires a debt issuance cost related to a recognized debt liability to be presented in the Consolidated Statement of Financial Position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. Further, ASU 2015-15 was issued in August 2015 to clarify the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit. The accounting updates are effective for financial statements issued for fiscal years beginning after December 15, 2015 on a retrospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements. Amendments to the Consolidation Analysis ASU 2015-02, issued in February 2015, revises the current consolidation guidance which results in a change in the determination of whether an entity consolidates certain types of legal entities. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The new standard is effective for annual and interim reporting periods beginning after December 15, 2015 and may be applied on a full or modified retrospective basis. Hybrid Financial Instruments Issued in the Form of a Share ASU 2014-16 was issued in November 2014 with the intent to eliminate the use of different methods in practice in the accounting for hybrid financial instruments issued in the form of a share. The new standard clarifies the evaluation of the economic characteristics and risks of a host contract in these hybrid financial instruments. The Company does not expect the adoption of ASU 2014-16 to have a material impact on its consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2015 and is to be applied on a modified retrospective basis. 102 Enbridge Inc. 2015 Annual Report
Development Stage Entities ASU 2014-10, issued in June 2014, amended the consolidation guidance to eliminate the development stage entity relief when applying the variable interest entity model and evaluating the sufficiency of equity at risk. The Company is currently evaluating the impact of the amendment to the consolidation guidance, which is effective for annual reporting periods beginning after December 15, 2015. The new standard requires these amendments be applied retrospectively. Revenue from Contracts with Customers ASU 2014-09 was issued in May 2014 with the intent of significantly enhancing comparability of revenue recognition practices across entities and industries. The new standard provides a single principles-based, five-step model to be applied to all contracts with customers and introduces new, increased disclosure requirements. The Company is currently assessing the impact of the new standard on its consolidated financial statements. In July 2015, the effective date of the new standard was delayed by one year and the new standard is now effective for annual and interim periods beginning on or after December 15, 2017 and may be applied on either a full or modified retrospective basis. Controls and Procedures Disclosure Controls and Procedures Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and United States securities law. As at December 31, 2015, an evaluation was carried out under the supervision of and with the participation of Enbridge’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of Enbridge’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by Enbridge in reports that it files with or submits to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required. Management’s Report on Internal Control Over Financial Reporting Management of Enbridge is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in the rules of the SEC and the Canadian Securities Administrators. The Company’s internal control over financial reporting is a process designed under the supervision and with the participation of executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with U.S. GAAP. The Company’s internal control over financial reporting includes policies and procedures that: pertain to the maintenance of records that, in reasonable • detail, accurately and fairly reflect transactions and dispositions of assets of the Company; provide reasonable assurance that transactions are recorded • as necessary to permit preparation of financial statements in accordance with U.S. GAAP; and provide reasonable assurance regarding prevention or timely • detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. The Company’s internal control over financial reporting may not prevent or detect all misstatements because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the Company’s policies and procedures. Management assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2015, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management concluded that the Company maintained effective internal control over financial reporting as at December 31, 2015. During the year ended December 31, 2015, there has been no material change in the Company’s internal control over financial reporting. The effectiveness of the Company’s internal control over financial reporting as at December 31, 2015 has been audited by PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company.
Management’s Report To the Shareholders of Enbridge Inc. Financial Reporting Management of Enbridge Inc. (the Company) is responsible for the accompanying consolidated financial statements and all related financial information contained in the annual report, including Management’s Discussion and Analysis. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) and necessarily include amounts that reflect management’s judgment and best estimates. The Board of Directors (the Board) and its committees are responsible for all aspects related to governance of the Company. The Audit, Finance & Risk Committee (the AF&RC) of the Board, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfill its responsibilities for financial reporting and internal controls related thereto. The AF&RC meets with management, internal auditors and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The AF&RC reports its findings to the Board for its consideration in approving the consolidated financial statements for issuance to the shareholders. The internal auditors and independent auditors have unrestricted access to the AF&RC. Internal Control over Financial Reporting Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting includes policies and procedures to facilitate the preparation of relevant, reliable and timely information, to prepare consolidated financial statements for external reporting purposes in accordance with U.S. GAAP and provide reasonable assurance that assets are safeguarded. Management assessed the effectiveness of the Company’s internal control over financial reporting as at December 31, 2015, based on the framework established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as at December 31, 2015. PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company, have conducted an audit of the consolidated financial statements of the Company and its internal control over financial reporting in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States) and have issued an unqualified audit report, which is accompanying the consolidated financial statements. Al Monaco John K. Whelen President & Executive Vice President & Chief Executive Officer Chief Financial Officer February 19, 2016 104 Enbridge Inc. 2015 Annual Report
Independent Auditor’s Report To the Shareholders of Enbridge Inc. We have completed integrated audits of Enbridge Inc.’s 2015, 2014 and 2013 consolidated financial statements and its internal control over financial reporting as at December 31, 2015. Our opinions, based on our audits are presented below. Report on the consolidated financial statements We have audited the accompanying consolidated financial statements of Enbridge Inc., which comprise the consolidated statements of financial position as at December 31, 2015 and December 31, 2014 and the consolidated statements of earnings, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2015, and the related notes, which comprise a summary of significant accounting policies and other explanatory information. Management’s responsibility for the consolidated financial statements Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepting in the United States of America and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. Auditor’s responsibility Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement. Canadian generally accepted auditing standards also require that we comply with ethical requirements. An audit involves performing procedures to obtain audit evidence, on a test basis, about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the company’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances. An audit also includes evaluating the appropriateness of accounting principles and policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion on the consolidated financial statements. Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Enbridge Inc. as at December 31 2015 and December 31, 2014 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015 in accordance with accounting principles generally accepted in the United States of America. Report on internal control over financial reporting We have also audited Enbridge Inc.’s internal control over financial reporting as at December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Consolidated Financial Statements 105
Management’s responsibility for internal control over financial reporting Management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying management’s report on internal control over financial reporting. Auditor’s responsibility Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control, based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our audit opinion on the company’s internal control over financial reporting. Definition of internal control over financial reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) 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. Inherent limitations Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, 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 that the degree of compliance with the policies or procedures may deteriorate. Opinion In our opinion, Enbridge Inc. maintained, in all material respects, effective internal control over financial reporting as at December 31, 2015, based on criteria established in Internal Control –Integrated Framework (2013) issued by COSO. Chartered Professional Accountants Calgary, Alberta February 19, 2016 106 Enbridge Inc. 2015 Annual Report
Consolidated Statements of Earnings Year ended December 31, 2015 2014 2013 (millions of Canadian dollars, except per share amounts) Revenues Commodity sales 23,842 28,281 26,039 Gas distribution sales 3,096 2,853 2,265 Transportation and other services 6,856 6,507 4,614 33,794 37,641 32,918 Expenses Commodity costs 22,949 27,504 25,222 Gas distribution costs 2,292 1,979 1,585 Operating and administrative 4,248 3,281 3,014 Depreciation and amortization 2,024 1,577 1,370 Environmental costs, net of recoveries (21) 100 362 Goodwill impairment (Note 15) 440 –– 31,932 34,441 31,553 1,862 3,200 1,365 Income from equity investments (Note 11) 475 368 330 Other expense (Note 27) (702) (266) (135) Interest expense (Note 17) (1,624) (1,129) (947) 11 2,173 613 Income taxes (Note 25) (170) (611) (123) Earnings/(loss) from continuing operations (159) 1,562 490 Discontinued operations (Note 9) Earnings from discontinued operations before income taxes – 73 6 Income taxes from discontinued operations – (27) (2) Earnings from discontinued operations – 46 4 Earnings/(loss) (159) 1,608 494 (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests 410 (203) 135 Earnings attributable to Enbridge Inc. 251 1,405 629 Preference share dividends (288) (251) (183) Earnings/(loss) attributable to Enbridge Inc. common shareholders (37) 1,154 446 Earnings/(loss) attributable to Enbridge Inc. common shareholders Earnings/(loss) from continuing operations (37) 1,108 442 Earnings from discontinued operations, net of tax – 46 4 (37) 1,154 446 Earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (Note 21) Continuing operations (0.04) 1.34 0.55 Discontinued operations – 0.05 – (0.04) 1.39 0.55 Diluted earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (Note 21) Continuing operations (0.04) 1.32 0.55 Discontinued operations – 0.05 – (0.04) 1.37 0.55 The accompanying notes are an integral part of these consolidated financial statements.
Consolidated Statements of Comprehensive Income Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Earnings/(loss) (159) 1,608 494 Other comprehensive income/(loss), net of tax Change in unrealized gains/(loss)on cash flow hedges 198 (833) 697 Change in unrealized loss on net investment hedges (903) (270) (96) Other comprehensive income from equity investees 30 10 11 Reclassification to earnings of realized cash flow hedges (191) 76 72 Reclassification to earnings of unrealized cash flow hedges (121) 158 39 Reclassification to earnings of pension plans and other postretirement benefits amortization amounts 21 15 27 Actuarial gains/(loss) on pension plans and other postretirement benefits 51 (191) 114 Change in foreign currency translation adjustment 3,347 1,238 710 Reclassification to earnings of derecognized cash flow hedges (Note 24) (247) –– Other comprehensive income 2,185 203 1,574 Comprehensive income 2,026 1,811 2,068 Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests 292 (242) (276) Comprehensive income attributable to Enbridge Inc. 2,318 1,569 1,792 Preference share dividends (288) (251) (183) Comprehensive income attributable to Enbridge Inc. common shareholders 2,030 1,318 1,609 108 Enbridge Inc. 2015 Annual Report
Consolidated Statements of Changes in Equity Year ended December 31, 2015 2014 2013 (millions of Canadian dollars, except per share amounts) Preference shares (Note 21) Balance at beginning of year 6,515 5,141 3,707 Preference shares issued – 1,374 1,434 Balance at end of year 6,515 6,515 5,141 Common shares (Note 21) Balance at beginning of year 6,669 5,744 4,732 Common shares issued – 446 582 Dividend reinvestment and share purchase plan 646 428 361 Shares is sued on exercise of stock options 76 51 69 Balance at end of year 7,391 6,669 5,744 Additional paid-in capital Balance at beginning of year 2,549 746 522 Stock-based compensation 35 31 28 Options exercised (19) (14) (17) Issuance of treasury stock – 22 208 Drop down of interest to Enbridge Energy Partners, L.P. (Note 20) 218 –– Enbridge Energy Partners, L.P. equity restructuring (Note 20) – 1,601 – Transfer of interest to Enbridge Income Fund – 176 – Drop down of interest to Midcoast Energy Partners, L.P. – (18) – Dilution gain on Enbridge Income Fund issuance of trust units (Note 20) 355 –– Dilution gain on Enbridge Income Fund equity investment (Note 20) 132 –– Dilution loss on Enbridge Income Fund indirect equity investment (Note 20) (5) –– Dilution gains and other 36 55 Balance at end of year 3,301 2,549 746 Retained earnings Balance at beginning of year 1,571 2,550 3,173 Earnings attributable to Enbridge Inc. 251 1,405 629 Preference share dividends (288) (251) (183) Common share dividends declared (1,596) (1,177) (1,035) Dividends paid to reciprocal shareholder 22 17 19 Reversal of cumulative redemption value adjustment attributable to Enbridge Commercial Trust (Note 20) 541 –– Redemption value adjustment attributable to redeemable noncontrolling interests (Note 20) (359) (973) (53) Balance at end of year 142 1,571 2,550 Accumulated other comprehensive income/(loss) (Note 23) Balance at beginning of year (435) (599) (1,762) Other comprehensive income attributable to Enbridge Inc. common shareholders 2,067 164 1,163 Balance at end of year 1,632 (435) (599) Reciprocal shareholding Balance at beginning of year (83) (86) (126) Issuance of treasury stock – 340 Balance at end of year (83) (83) (86) Total Enbridge Inc. shareholders’ equity 18,898 16,786 13,496 Noncontrolling interests (Note 20) Balance at beginning of year 2,015 4,014 3,258 Earnings/(loss) attributable to noncontrolling interests (407) 214 (111) Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax Change in unrealized gains/(loss) on cash flow hedges 161 (192) 166 Change in foreign currency translation adjustment 273 146 223 Reclassification to earnings of realized cash flow hedges (236) 18 4 Reclassification to earnings of unrealized cash flow hedges (83) 77 14 115 49 407 Comprehensive income/(loss) attributable to noncontrolling interests (292) 263 296 Distributions (Note 20) (680) (535) (468) Contributions (Note 20) 615 212 922 Dilution loss (53) –– Acquisitions–Magic Valley and Wildcat wind farms (Note 6) – 351 – Drop down of interest to Enbridge Energy Partners, L.P. (Note 20) (304) –– Enbridge Energy Partners, L.P. equity restructuring (Note 20) – (2,330) – Drop down of interest to Midcoast Energy Partners, L.P. (Note 20) – 39 – Other (1) 16 Balance at end of year 1,300 2,015 4,014 Total equity 20,198 18,801 17,510 Dividends paid per common share 1.86 1.40 1.26 The accompanying notes are an integral part of these consolidated financial statements. Consolidated Financial Statements 109
Consolidated Statements of Cash Flows Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Operating activities Earnings/(loss) (159) 1,608 494 Earnings from discontinued operations – (46) (4) Depreciation and amortization 2,024 1,577 1,370 Deferred income taxes (Note 25) 7 587 131 Changes in unrealized (gains)/loss on derivative instruments, net 2,373 (96) 1,262 Cash distributions in excess of equity earnings 244 196 355 Impairment (Notes 9 and 15) 536 18 6 Gains on dispositions (Notes 6 and 27) (94) (38) (18) Hedge ineffectiveness (20) 210 48 Inventory revaluation allowance 410 174 4 Other (62) 115 (43) Changes in regulatory assets and liabilities 41 22 (11) Changes in environmental liabilities, net of recoveries (43) (78) 148 Changes in operating assets and liabilities (Note 29) (686) (1,721) (409) Cash provided by continuing operations 4,571 2,528 3,333 Cash provided by discontinued operations (Note 9) – 19 8 4,571 2,547 3,341 Investing activities Additions to property, plant and equipment (7,273) (10,524) (8,235) Long-term investments (622) (854) (1,018) Restricted long-term investments (Note 12) (49) –– Additions to intangible assets (101) (208) (212) Acquisitions (106) (394) – Proceeds from disposition 146 85 41 Affiliate loans, net 59 13 8 Changes in restricted cash 13 (13) (15) Cash used in continuing operations (7,933) (11,895) (9,431) Cash provided by discontinued operations (Note 9) – 4– (7,933) (11,891) (9,431) Financing activities Net change in bank indebtedness and short-term borrowings (588) 734 (350) Net change in commercial paper and credit facility draws 1,507 4,212 1,562 Southern Lights project financing repayments – (1,519) (5) Debenture and term note issues – Southern Lights – 1,507 – Debenture and term note issues 3,767 5,414 2,845 Debenture and term note repayments (1,023) (1,348) (660) Contributions from noncontrolling interests 615 212 922 Distributions to noncontrolling interests (680) (535) (468) Contributions from redeemable noncontrolling interests 670 323 92 Distributions to redeemable noncontrolling interests (114) (79) (72) Preference shares issued – 1,365 1,428 Common shares issued 57 478 628 Preference share dividends (288) (245) (178) Common share dividends (950) (749) (674) 2,973 9,770 5,070 Effect of translation of foreign denominated cash and cash equivalents 143 59 20 Increase/(decrease) in cash and cash equivalents (246) 485 (1,000) Cash and cash equivalents at beginning of year – continuing operations 1,261 756 1,776 Cash and cash equivalents at beginning of year – discontinued operations – 20 – Cash and cash equivalents at end of year 1,015 1,261 776 Cash and cash equivalents– discontinued operations – –(20) Cash and cash equivalents – continuing operations 1,015 1,261 756 Supplementary cash flow information Income taxes paid 80 9107 Interest paid 1,835 1,435 1,097 The accompanying notes are an integral part of these consolidated financial statements. 110 Enbridge Inc. 2015 Annual Report
Consolidated Statements of Financial Position December 31, 2015 2014 (millions of Canadian dollars; number of shares in millions) Assets Current assets Cash and cash equivalents 1,015 1,261 Restricted cash 34 47 Accounts receivable and other (Note 7) 5,430 5,504 Accounts receivable from affiliates 7 241 Inventory (Note 8) 1,111 1,148 7,597 8,201 Property, plant and equipment, net (Note 9) 64,434 53,830 Long-term investments (Note 11) 7,008 5,408 Restricted long-term investments (Note 12) 49 – Deferred amounts and other assets (Note 13) 3,309 3,208 Intangible assets, net (Note 14) 1,348 1,166 Goodwill (Note 15) 80 483 Deferred income taxes (Note 25) 839 561 84,664 72,857 Liabilities and equity Current liabilities Bank indebtedness 361 507 Short-term borrowings (Note 17) 599 1,041 Accounts payable and other (Note 16) 7,351 6,444 Accounts payable to affiliates 48 80 Interest payable 324 264 Environmental liabilities 141 161 Current maturities of long-term debt (Note 17) 1,990 1,004 10,814 9,501 Long-term debt (Note 17) 39,540 33,423 Other long-term liabilities (Note 18) 6,056 4,041 Deferred income taxes (Note 25) 5,915 4,842 62,325 51,807 Commitments and contingencies (Note 31) Redeemable non controlling interests (Note 20) 2,141 2,249 Equity Share capital (Note 21) Preference shares 6,515 6,515 Common shares (868and852outstanding at December 31,2015and2014,respectively) 7,391 6,669 Additional paid-in capital 3,301 2,549 Retained earnings 142 1,571 Accumulated other comprehensive income/(loss) (Note 23) 1,632 (435) Reciprocal shareholding (83) (83) Total Enbridge Inc. shareholders’ equity 18,898 16,786 Non controlling interests (Note 20) 1,300 2,015 20,198 18,801 84,664 72,857 The accompanying notes are an integral part of these consolidated financial statements. Approved by the Board of Directors: David A. Arledge J. Herb England Chair Director Consolidated Financial Statements 111
Notes to the Consolidated Financial Statements 1. General Business Description Enbridge Inc. (Enbridge or the Company) is a publicly traded energy transportation and distribution company. Enbridge conducts its business through five business segments: Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services; Sponsored Investments and Corporate. These operating segments are strategic business units established by senior management to facilitate the achievement of the Company’s long-term objectives, to aid in resource allocation decisions and to assess operational performance. Effective September 1, 2015, under an agreement with Enbridge Income Fund (the Fund) and Enbridge Income Fund Holdings Inc. (ENF), Enbridge transferred its Canadian Liquids Pipelines business, held by Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines (Athabasca) Inc. (EPAI), and certain Canadian renewable energy assets to the Fund Group (comprising the Fund, Enbridge Commercial Trust (ECT), Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP) for consideration valued at $30.4 billion plus incentive distribution and performance rights (the Canadian Restructuring Plan). The consideration that Enbridge received included $18.7 billion of units in the Fund Group, comprised of $3 billion of Fund units and $15.7 billion of equity units of EIPLP, in which the Fund has an interest. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion. Upon closing of the transaction, Enbridge’s overall economic interest in the Fund Group increased to 91.9% (overall economic interest prior to the transfer was 66.4%). Also effective September 1, 2015, the transferred businesses and assets noted above are reported under the Sponsored Investments segment as further described below. Liquids Pipelines Until August 31, 2015, Liquids Pipelines consisted of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines and terminals in Canada and the United States, including Canadian Mainline, Regional Oil Sands System, Seaway Crude Pipeline System (Seaway Pipeline), Flanagan South Pipeline, Southern Lights Pipeline, Spearhead Pipeline and Feeder Pipelines and Other. Effective September 1, 2015, under the Canadian Restructuring Plan described above, Enbridge transferred to the Fund Group the Canadian Mainline, Regional Oil Sands System, the Canadian portion of the Southern Lights Pipeline (Southern Lights Canada) and certain residual rights and/or obligations relating to terminal and storage assets. These transferred assets are reported under the Sponsored Investments segment from the date of transfer. Gas Distribution Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD), which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick. Gas Pipelines, Processing and Energy Services Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines, gathering and processing facilities and the Company’s energy services businesses, along with renewable energy and transmission facilities. Effective September 1, 2015, under the Canadian Restructuring Plan described above, Enbridge transferred to the Fund Group certain Canadian renewable energy assets which are reported under the Sponsored Investments segment from the date of transfer. Investments in natural gas pipelines include the Company’s interests in the Vector Pipeline (Vector) and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in Aux Sable, a natural gas extraction and fractionation business located near the terminus of the Alliance Pipeline and Canadian Midstream assets located in northeast British Columbia and northwest Alberta. The energy services businesses undertake physical commodity marketing activity and logistical services, oversee refinery supply services and manage the Company’s volume commitments on Alliance Pipeline, Vector and other pipeline systems. Sponsored Investments Sponsored Investments, as at December 31, 2015, include the Company’s overall 89.2% (2014 – 66.4%) economic interest in the Fund Group. Also within Sponsored Investments is the Company’s 35.7% (2014 – 33.7%) economic interest in Enbridge Energy Partners, L.P. (EEP) and Enbridge’s interests in both the Eastern Access and Lakehead System Mainline Expansion projects held through Enbridge Energy, Limited Partnership. Enbridge, through its subsidiaries, manages the day-to-day operations of and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities. As a result of the Canadian Restructuring Plan, as discussed above, effective September 1, 2015, the Fund Group’s primary operations include its liquids pipelines business, which includes the Canadian Mainline and Regional Oil Sands System, its renewable power generation assets and a natural gas transmission business through its 50% interest in Alliance Pipeline. EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines, including the Lakehead Pipeline System (Lakehead System), which is the United States portion of the Enbridge mainline system, and transports, gathers, processes and markets natural gas and NGL. Corporate Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, general corporate investments and financing costs not allocated to the business segments. 112 Enbridge Inc. 2015 Annual Report
2. Summary of Significant Accounting Policies These consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). Amounts are stated in Canadian dollars unless otherwise noted. As a Securities and Exchange Commission registrant, the Company is permitted to use U.S. GAAP for purposes of meeting both its Canadian and United States continuous disclosure requirements. Basis of Presentation and Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: carrying values of regulatory assets and liabilities (Note 5); unbilled revenues (Note 7); allowance for doubtful accounts (Note 7); depreciation rates and carrying value of property, plant and equipment (Note 9); amortization rates of intangible assets (Note 14); measurement of goodwill (Note 15); fair value of asset retirement obligations (ARO) (Note 19); valuation of stock-based compensation (Note 22); fair value of financial instruments (Note 24); provisions for income taxes (Note 25); assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 26); commitments and contingencies (Note 31); and estimates of losses related to environmental remediation obligations (Note 31). Actual results could differ from these estimates. Principles of Consolidation The consolidated financial statements include the accounts of Enbridge, its subsidiaries and variable interest entities (VIEs) for which the Company is the primary beneficiary. Upon inception of a contractual agreement, the Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. Where the Company concludes it is the primary beneficiary of a VIE, the Company will consolidate the accounts of that entity. The consolidated financial statements also include the accounts of any limited partnerships where the Company represents the general partner and, based on all facts and circumstances, controls such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where the Company retains an undivided interest in assets and liabilities, Enbridge records its proportionate share of assets, liabilities, revenues and expenses. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests and redeemable noncontrolling interests. Investments and entities over which the Company exercises significant influence are accounted for using the equity method. As a result of the Canadian Restructuring Plan, ECT, a subsidiary of the Company, determines its equity investment earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the HLBV method to its equity method investments where cash distributions, including both preference and residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that ECT would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s share of the earnings or losses from the equity investment for the period. While ECT and EIPLP are both consolidated in these financial statements, the use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of Earnings. The Company continues to recognize Redeemable noncontrolling interests on the Consolidated Statements of Financial Position at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares. Regulation Certain of the Company’s businesses are subject to regulation by various authorities including, but not limited to, the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, the New Brunswick Energy and Utilities Board (EUB) and the Ontario Energy Board (OEB). Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative (LMCI). Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if the Company identifies an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, the Company would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. Notes to the Consolidated Financial Statements 113
Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. In the absence of rate regulation, the Company would capitalize interest using a capitalization rate based on its cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized. For certain regulated operations to which U.S. GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with U.S. GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with U.S. GAAP and no deferred regulatory asset is recorded (Note 5). With the approval of the regulator, EGD and certain distribution operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. To the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of capitalized costs could differ significantly from those recorded. In the absence of rate regulation, a portion of such costs may be charged to current period earnings. Revenue Recognition For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer credit worthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts rateably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. The Company recognizes revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote. Certain offshore pipeline transportation contracts require the Company to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay the Company a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized rateably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Since July 1, 2011 onward, Canadian Mainline (excluding Lines 8 and 9) earnings are governed by the Competitive Toll Settlement (CTS), under which revenues are recorded when services are performed. Effective on that date, the Company prospectively discontinued the application of rate-regulated accounting for those assets with the exception of flow-through income taxes covered by a specific rate order. For natural gas utility rate-regulated operations in Gas Distribution, revenues are recognized in a manner consistent with the underlying rate-setting mechanism as mandated by the regulator. Natural gas utilities revenues are recorded on the basis of regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in the Company’s distribution franchise area. For natural gas and marketing businesses, an estimate of revenues and commodity costs for the month of December is included in the Consolidated Statements of Earnings for each year based on the best available volume and price data for the commodity delivered and received. Derivative Instruments and Hedging Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Transportation and other services revenues, Commodity costs, Operating and administrative expense, Other income/(expense) and Interest expense. Derivatives in Qualifying Hedging Relationships The Company uses derivative financial instruments to manage its exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to its share price. Hedge accounting is optional and requires the Company to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. The Company presents the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges and net investment hedges. Cash Flow Hedges The Company uses cash flow hedges to manage its exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to its share price. The effective portion of the change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/ (loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings. Any hedge ineffectiveness is recorded in current period earnings.
If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized concurrently with the related transaction. If a hedged anticipated transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges The Company may use fair value hedges to hedge the fair value of debt instruments or commodity positions. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged asset or liability, otherwise required to be carried at cost or amortized cost, ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Net Investment Hedges Gains and losses arising from translation of net investment in foreign operations from their functional currencies to the Company’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA). The Company designates foreign currency derivatives and United States dollar denominated debt as hedges of net investments in United States dollar denominated foreign operations. As a result, the effective portion of the change in the fair value of the foreign currency derivatives as well as the translation of United States dollar denominated debt are reflected in OCI and any ineffectiveness is reflected in current period earnings. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from disposal of a foreign operation. Classification of Derivatives The Company recognizes the fair market value of derivative instruments on the Consolidated Statements of Financial Position as current and long-term assets or liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Operating activities on the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when the Company has the legal right and intention to settle them on a net basis. Transaction Costs Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. The Company incurs transaction costs primarily from the issuance of debt and classifies these costs as Deferred amounts and other assets. These costs are amortized using the effective interest rate method over the life of the related debt instrument. Equity Investments Equity investments over which the Company exercises significant influence, but does not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for the Company’s proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to and decreased for distributions received from the investees. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, the Company capitalizes interest costs associated with its investment during such period. Restricted Long-Term Investments Long-term investments that are restricted as to withdrawal or usage, for the purposes of the NEB’s LMCI, are presented as Restricted long-term investments on the Consolidated Statements of Financial Position. Other Investments Generally, the Company classifies equity investments in entities over which it does not exercise significant influence and that do not trade on an actively quoted market as other investments carried at cost. Financial assets in this category are initially recorded at fair value with no subsequent re-measurement. Any investments which do trade on an active market are classified as available for sale investments measured at fair value through OCI. Dividends received from investments carried at cost are recognized in earnings when the right to receive payment is established. Noncontrolling Interests Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries, limited partnerships and VIEs. The portion of equity not owned by the Company in such entities is reflected as noncontrolling interests within the equity section of the Consolidated Statements of Financial Position and, in the case of redeemable noncontrolling interests, within the mezzanine section of the Consolidated Statements of Financial Position between long-term liabilities and equity. The Fund’s noncontrolling interest holders have the option to redeem the Fund trust units for cash, subject to certain limitations. Redeemable noncontrolling interests are recognized at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares. On a quarterly basis, changes in estimated redemption values are reflected as a charge or credit to retained earnings. The use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of Earnings. Notes to the Consolidated Financial Statements 115
Income Taxes The liability method of accounting for income taxes is followed. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For the Company’s regulated operations, a deferred income tax liability is recognized with a corresponding regulatory asset to the extent taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income taxes. Foreign Currency Transactions and Translation Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which the Company or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise. Gains and losses arising from translation of foreign operations’ functional currencies to the Company’s Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect on the balance sheet date, while revenues and expenses are translated using monthly average exchange rates. Cash and Cash Equivalents Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased. Restricted Cash Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as Restricted cash on the Consolidated Statements of Financial Position. Loans and Receivables Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. Allowance for Doubtful Accounts Allowance for doubtful accounts is determined based on collection history. When the Company has determined that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts are applied against the impaired accounts receivable. Inventory Inventory is comprised of natural gas in storage held in EGD and crude oil and natural gas held primarily by energy services businesses in the Gas Pipelines, Processing and Energy Services and Sponsored Investments segments. Natural gas in storage in EGD is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of the gas purchased is deferred as a liability for future refund or as an asset for collection as approved by the OEB. Other commodities inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs on the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. Property, Plant and Equipment Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. The Company capitalizes interest incurred during construction for non rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are not reflected in earnings but are booked as an adjustment to accumulated depreciation. Deferred Amounts and Other Assets Deferred amounts and other assets primarily include: costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates including deferred income taxes; contractual receivables under the terms of long-term delivery contracts; derivative financial instruments; and deferred financing costs. Deferred financing costs are amortized using the effective interest method over the term of the related debt and are recorded in Interest expense. Intangible Assets Intangible assets consist primarily of certain software costs, natural gas supply opportunities, acquired power purchase agreements, land leases and permits. The Company capitalizes costs incurred during the application development stage of internal use software projects. Natural gas supply opportunities are growth opportunities, identified upon acquisition, present in gas producing zones where certain of Enbridge Inc. 2015 Annual Report
EEP’s gas systems are located. Intangible assets are amortized on a straight-line basis over their expected lives, commencing when the asset is available for use. Goodwill Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. For the purposes of impairment testing, reporting units are identified as business operations within an operating segment. The Company has the option to first assess qualitative factors to determine whether it is necessary to perform the two-step goodwill impairment test. If the two-step goodwill impairment test is performed, the first step involves determining the fair value of the Company’s reporting units inclusive of goodwill and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured as the excess of the carrying amount of the reporting unit’s allocated goodwill over the implied fair value of the goodwill based on the fair value of the reporting unit’s assets and liabilities. Impairment The Company reviews the carrying values of its long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the undiscounted cashflows expected from the asset, the asset is written down to fair value. With respect to investments in debt and equity securities, the Company assesses at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is determined to be objective evidence of impairment, the Company internally values the expected discounted cashflows using observable market inputs and determines whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset. With respect to other financial assets, the Company assesses the assets for impairment when it no longer has reasonable assurance of timely collection. If evidence of impairment is noted, the Company reduces the value of the financial asset to its estimated realizable amount, determined using discounted expected future cashflows. Asset Retirement Obligations ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. The Company’s estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. For the majority of the Company’s assets, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements. Retirement and Postretirement Benefits The Company maintains pension plans which provide defined benefit and defined contribution pension benefits. Defined benefit pension plan costs are determined using actuarial methods and are funded through contributions determined using the projected benefit method, which incorporates management’s best estimates of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors including discount rates and mortality. In 2014, new mortality tables were issued by the Society of Actuaries in the United States which were further revised in 2015. These tables, along with the Canadian Institute of Actuaries tables that were revised in 2013, were used by the Company for measurement of its benefit obligations of its United States pension plan (the United States Plan) and the Canadian pension plans (the Canadian Plans), respectively. The Company determines discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments the Company anticipates making under each of the respective plans. Pension cost is charged to earnings and includes: Cost of pension plan benefits provided in exchange for employee • services rendered during the year; Interest cost of pension plan obligations; • Expected return on pension plan assets; • Amortization of the prior service costs and amendments on a • straight-line basis over the expected average remaining service period of the active employee group covered by the plans; and Amortization of cumulative unrecognized net actuarial gains • and losses in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans. Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets for that period or from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate, changes in headcount or salary inflation experience. Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using market related values and assumptions on the specific invested asset mix within the pension plans. The market related values reflect estimated return on investments consistent with long-term historical averages for similar assets. Notes to the Consolidated Financial Statements 117
For defined contribution plans, contributions made by the Company are expensed in the period in which the contribution occurs. The Company also provides OPEB other than pensions, including group health care and life insurance benefits for eligible retirees, their spouses and qualified dependents. The cost of such benefits is accrued during the years in which employees render service. The overfunded or underfunded status of defined benefit pension and OPEB plans is recognized as Deferred amounts and other assets, Accounts payable and other or Other long-term liabilities, on the Consolidated Statements of Financial Position. A plan’s funded status is measured as the difference between the fair value of plan assets and the plan’s projected benefit obligation. Any unrecognized actuarial gains and losses and prior service costs and credits that arise during the period are recognized as a component of OCI, net of tax. Certain regulated utility operations of the Company record regulatory adjustments to reflect the difference between pension expense and OPEB costs for accounting purposes and the pension expense and OPEB costs for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent pension expense or OPEB costs are expected to be collected from or refunded to customers, respectively, in future rates. In the absence of rate regulation, regulatory balances would not be recorded and pension and OPEB costs would be charged to earnings and OCI on an accrual basis. Stock-Based Compensation Incentive Stock Options (ISO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISO granted as calculated by the Black-Scholes-Merton model and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility, with a corresponding credit to Additional paid-in capital. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised. Performance stock options (PSO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the PSO granted as calculated by the Bloomberg barrier option valuation model and is recognized over the vesting period with a corresponding credit to Additional paid-in capital. The options become exercisable when both performance targets and time vesting requirements have been met. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised. Performance Stock Units (PSU) and Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each reporting period. PSU vest at the completion of a three-year term and RSU vest at the completion of a 35-month term. During the vesting term, compensation expense is recorded based on the number of units outstanding and the current market price of the Company’s shares with an offset to Accounts payable and other or to Other long-term liabilities. The value of the PSU is also dependent on the Company’s performance relative to performance targets set out under the plan. Commitments, Contingencies and Environmental Liabilities The Company expenses or capitalizes, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. The Company expenses costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. The Company records liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. The Company’s estimates are subject to revision in future periods based on actual costs or new information and are included in Environmental liabilities and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. The Company evaluates recoveries from insurance coverage separately from the liability and, when recovery is probable, the Company records and reports an asset separately from the associated liability in the Consolidated Statements of Financial Position. Liabilities for other commitments and contingencies are recognized when, after fully analysing available information, the Company determines it is either probable that an asset has been impaired, or that a liability has been incurred, and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, the Company recognizes the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. The Company expenses legal costs associated with loss contingencies as such costs are incurred. 118 Enbridge Inc. 2015 Annual Report
3. Changes in Accounting Policies Adoption of New Standards Extraordinary and Unusual Items Effective January 1, 2015, the Company retrospectively adopted Accounting Standards Update (ASU) 2015-01 which eliminates the concept of extraordinary items from U.S. GAAP. Entities will no longer be required to separately classify and present extraordinary items in the Consolidated Statements of Earnings. There was no material impact to the Company’s consolidated financial statements as a result of adopting this update. Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity Effective January 1, 2015, the Company prospectively adopted ASU 2014-08 which changes the criteria and disclosures for reporting discontinued operations. The revised criteria will in general, result in fewer transactions being categorized as discontinued operations. There was no material impact to the consolidated financial statements as a result of adopting this update. Future Accounting Policy Changes Recognition and Measurement of Financial Assets and Liabilities ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation, and disclosure of financial assets and liabilities. The amendments revise accounting related to the classification and measurement of investments in equity securities, the presentation of certain fair value changes for financial liabilities measured at fair value, and the disclosure requirements associated with the fair value of financial instruments. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2017, and is to be applied by means of a cumulative-effect adjustment to the Statement of Financial Position as of the beginning of the fiscal year of adoption, with amendments related to equity securities without readily determinable fair values to be applied prospectively. Classification of Deferred Taxes on the Statement of Financial Position ASU 2015-17 was issued in November 2015 with the intent to simplify the presentation of deferred income taxes. The amendments require that deferred tax liabilities and assets be classified as noncurrent in a Statement of Financial Position. The accounting update is effective for fiscal years beginning after December 15, 2016 and is to be applied on a prospective or retrospective basis. The Company is currently assessing the impact of the new standard on its consolidated financial statements. Early application is permitted for all entities as of the beginning of an interim or annual reporting period. Effective January 1, 2016, the Company will elect to early adopt ASU 2015-17. Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations ASU 2015-16 was issued in September 2015 with the intent to simplify the accounting for measurement-period adjustments in business combinations. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The accounting update is effective for fiscal years beginning after December 15, 2015 and is to be applied on a prospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements. Simplifying the Measurement of Inventory ASU 2015-11 was issued in July 2015 with the intent to simplify the measurement of inventory. The new standard requires inventory to be measured at the lower of cost and net realizable value and is applicable to all inventory, with the exception of inventory measured using last-in, first-out or the retail inventory method. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The new standard is effective for annual and interim reporting periods beginning after December 15, 2016 and is to be applied on a prospective basis. Measurement Date of Defined Benefit Obligation and Plan Assets ASU 2015-04 was issued in April 2015 with the intent to simplify the fair value measurement of defined benefit plan assets and obligations. For entities with a fiscal year end that does not coincide with a month end, the new standard permits an entity to measure its defined benefit plan assets and obligations using the month end that is closest to the entity’s fiscal year end. In addition, where there are significant events in an interim period that would trigger a re-measurement of the plan assets and obligations, an entity is also permitted to re-measure such assets and obligations using the month end that is closest to the date of the significant event. The accounting update is effective for financial statements issued for fiscal years beginning after December 15, 2015 and is to be applied on a prospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements. Simplifying the Presentation of Debt Issuance Costs ASU 2015-03 was issued in April 2015 with the intent to simplify the presentation of debt issuance costs. The new standard requires a debt issuance cost related to a recognized debt liability to be presented in the Consolidated Statements of Financial Position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. Further, ASU 2015-15 was issued in August 2015 to clarify the presentation and subsequent measurement of debt issuance costs Notes to the Consolidated Financial Statements 119
associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit. The accounting updates are effective for financial statements issued for fiscal years beginning after December 15, 2015 on a retrospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated financial statements. Amendments to the Consolidation Analysis ASU 2015-02, issued in February 2015, revises the current consolidation guidance which results in a change in the determination of whether an entity consolidates certain types of legal entities. The Company is currently assessing the impact of the new standard on its consolidated financial statements. The new standard is effective for annual and interim reporting periods beginning after December 15, 2015 and may be applied on a full or modified retrospective basis. Hybrid Financial Instruments Issued in the Form of a Share ASU 2014-16 was issued in November 2014 with the intent to eliminate the use of different methods in practice in the accounting for hybrid financial instruments issued in the form of a share. The new standard clarifies the evaluation of the economic characteristics and risks of a host contract in these hybrid financial instruments. The Company does not expect the adoption of ASU 2014-16 to have a material impact on its consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2015 and is to be applied on a modified retrospective basis. Development Stage Entities ASU 2014-10, issued in June 2014, amended the consolidation guidance to eliminate the development stage entity relief when applying the VIE model and evaluating the sufficiency of equity at risk. The Company is currently evaluating the impact of the amendment to the consolidation guidance, which is effective for annual reporting periods beginning after December 15, 2015. The new standard requires these amendments be applied retrospectively. Revenue from Contracts with Customers ASU 2014-09 was issued in May 2014 with the intent of significantly enhancing comparability of revenue recognition practices across entities and industries. The new standard provides a single principles-based, five-step model to be applied to all contracts with customers and introduces new, increased disclosure requirements. The Company is currently assessing the impact of the new standard on its consolidated financial statements. In July 2015, the effective date of the new standard was delayed by one year and the new standard is now effective for annual and interim periods beginning on or after December 15, 2017 and may be applied on either a full or modified retrospective basis. 120 Enbridge Inc. 2015 Annual Report
4. Segmented Information Gas Pipelines, Processing Liquids Gas and Energy Sponsored 1 1 1 2 YearendedDecember31,2015 Pipelines Distribution Services Investments Corporate Consolidated (millions of Canadian dollars) Revenues 1,730 3,560 20,862 7,642 – 33,794 Commodity and gas distribution costs (8) (2,300) (20,008) (2,927) 2 (25,241) Operating and administrative (1,223) (537) (238) (2,211) (39) (4,248) Depreciation and amortization (520) (308) (178) (986) (32) (2,024) Environmental costs, net of recoveries 4– – 17 – 21 Goodwill impairment – – – (440) – (440) (17) 415 438 1,095 (69) 1,862 Income/(loss) from equity investments 296 – (13) 201 (9) 475 Other income/(expense) 11 (1) 20 (33) (699) (702) Interest expense (532) (168) (109) (661) (154) (1,624) Income taxes recovery/(expense) 20 (24) (142) (499) 475 (170) Earnings/(loss) (222) 222 194 103 (456) (159) Earnings/(loss) attributable to noncontrolling interests and redeemable noncontrolling interests (2) – 24 376 12 410 Preference share dividends –– –– (288) (288) Earnings/(loss) attributable to Enbridge Inc. common shareholders (224) 222 218 479 (732) (37) 3 Additions to property, plant and equipment 2,957 858 226 3,158 76 7,275 Total assets 12,541 9,546 7,793 50,237 4,547 84,664 Gas Pipelines, Processing Liquids Gas and Energy Sponsored 1 1,4 1,4 2 Yearended December31, 2014 Pipelines Distribution Services Investments Corporate Consolidated (millions of Canadian dollars) Revenues 2,283 3,216 23,023 9,119 – 37,641 Commodity and gas distribution costs – (1,979) (21,921) (5,583) – (29,483) Operating and administrative (1,101) (530) (175) (1,438) (37) (3,281) Depreciation and amortization (498) (304) (114) (642) (19) (1,577) Environmental costs, net of recoveries 7 – – (107) – (100) 691 403 813 1,349 (56) 3,200 Income/(loss) from equity investments 160 – 136 86 (14) 368 Other income/(expense) 12 (8) 38 5 (313) (266) Interest income/(expense) (372) (165) (98) (559) 65 (1,129) Income taxes recovery/(expense) (24) (17) (318) (263) 11 (611) Earnings/(loss) from continuing operations 467 213 571 618 (307) 1,562 Discontinued operations Earnings from discontinued operations before income taxes – – 73 – – 73 Income taxes from discontinued operations – – (27) – – (27) Earnings from discontinued operations – – 46 – – 46 Earnings/(loss) 467 213 617 618 (307) 1,608 Earnings attributable to noncontrolling interests and redeemable noncontrolling interests (4) – – (199) – (203) Preference share dividends – – – – (251) (251) Earnings/(loss) attributable to Enbridge Inc. common shareholders 463 213 617 419 (558) 1,154 3 Additions to property, plant and equipment 5,917 603 678 3,269 60 10,527 1 Total assets 27,657 9,320 7,601 23,515 4,764 72,857 Notes to the Consolidated Financial Statements 121
Gas Pipelines, Processing Liquids Gas and Energy Sponsored 1 1,4 1,4 2 Yearended December31, 2013 Pipelines Distribution Services Investments Corporate Consolidated (millions of Canadian dollars) Revenues 2,272 2,741 20,310 7,595 – 32,918 Commodity and gas distribution costs – (1,585) (20,244) (4,978) – (26,807) Operating and administrative (1,006) (534) (221) (1,226) (27) (3,014) Depreciation and amortization (429) (321) (75) (530) (15) (1,370) Environmental costs, net of recoveries (79) – – (283) – (362) 758 301 (230) 578 (42) 1,365 Income from equity investments 118 – 154 56 2 330 Other income/(expense) 39 20 39 37 (270) (135) Interest income/(expense) (319) (160) (81) (409) 22 (947) Income taxes recovery/(expense) (165) (32) 50 (133) 157 (123) Earnings/(loss) from continuing operations 431 129 (68) 129 (131) 490 Discontinued operations Earnings from discontinued operations before income taxes –– 6 – – 6 Income taxes from discontinued operations – – (2) – – (2) Earnings from discontinued operations –– 4 – – 4 Earnings/(loss) 431 129 (64) 129 (131) 494 (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests (4) – – 139 – 135 Preference share dividends – – – – (183) (183) Earnings/(loss) attributable to Enbridge Inc. common shareholders 427 129 (64) 268 (314) 446 3 Additions to property, plant and equipment 4,360 533 744 2,565 34 8,236 1 Ef fective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group within the Sponsored Investments segment as described under the Canadian Restructuring Plan (Note 1). Revenues of $603 million and loss of $403 million in the year ended December 31, 2015 (2014 – revenues of $1,679 million and earnings of $320 million; 2013 – revenues of $1,752 million and earnings of $261 million) which relate to Liquids Pipelines assets prior to the transfer have not been reclassified into the Sponsored Investments segment for presentation purposes. Revenues of $83 million and earnings of $1 million in the year ended December 31, 2015 (2014 – revenues of $91 million and loss of $2 million; 2013 – revenues of $44 million and loss of $55 million) which relate to Gas Pipelines, Processing and Energy Services assets prior to the transfer have not been reclassified into the Sponsored Investments segment for presentation purposes. Additionally, Liquids Pipelines assets of $17,766 million as at December 31, 2014 and Gas Pipelines, Processing and Energy Services assets of $1,095 million as at December 31, 2014 have not been reclassified into the Sponsored Investments segment for presentation purposes. 2 Included within the Corporate segment was Interest income of $822 million (2014 – $694 million; 2013 – $443 million) charged to other operating segments. 3 Includes allowance for equity funds used during construction. 4 In November 2014, Enbridge’s 50% interest in the United States portion of Alliance Pipeline (Alliance Pipeline US) was transferred to the Fund Group within the Sponsored Investments segment. Earnings from the assets prior to the date of transfer of $41 million (2013 – $43 million) have not been reclassified between segments for presentation purposes. The measurement basis for preparation of segmented information is consistent with the significant accounting policies(Note 2). Out-Of-Period Adjustment Earnings attributable to Enbridge Inc. common shareholders for the year ended December 31, 2015 were increased by an out-of-period adjustment of $71 million within the Corporate segment in respect of an overstatement of deferred income tax expense in 2013 and 2014. Geographic Information 1 Revenues Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Canada 11,087 14,963 12,690 United States 22,707 22,678 20,228 33,794 37,641 32,918 1 Revenues are based on the country of origin of the product or service sold. Property, Plant and Equipment December 31, 2015 2014 (millions of Canadian dollars) Canada 30,656 27,420 United States 33,778 26,410 64,434 53,830 122 Enbridge Inc. 2015 Annual Report
5. Financial Statement Effects of Rate Regulation General Information on Rate Regulation and its Economic Effects A number of businesses within the Company are subject to regulation. The Company’s significant regulated businesses and related accounting impacts are described below. Canadian Mainline Canadian Mainline includes the Canadian portion of the mainline system and is subject to regulation by the NEB. Canadian Mainline tolls (excluding Lines 8 and 9) are currently governed by the 10-year CTS, which establishes a Canadian Local Toll for all volumes shipped on the Canadian Mainline and an International Joint Tariff for all volumes shipped from western Canadian receipt points to delivery points on the Lakehead System and delivery points on the Canadian Mainline downstream of the Lakehead System. The CTS was negotiated with shippers in accordance with NEB guidelines, was approved by the NEB in June 2011 and took effect July 1, 2011. Under the CTS, a regulatory asset is recognized to offset deferred income taxes as a NEB rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the CTS. Southern Lights Pipeline The United States portion of the Southern Lights Pipeline (Southern Lights US) is regulated by the FERC and Southern Lights Canada is regulated by the NEB. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost of service toll methodology. Toll adjustments are filed annually with the regulators. Tariffs provide for recovery of allowable operating and debt financing costs, plus a pre-determined after-tax rate of return on equity (ROE) of 10%. Southern Lights Pipeline tolls are based on a deemed 70% debt and 30% equity structure. Enbridge Gas Distribution EGD’s gas distribution operations are regulated by the OEB. Rates for the years ended December 31, 2015 and 2014 were set in accordance with parameters established by the customized incentive rate plan (IR Plan). The customized IR Plan was approved in 2014 by the OEB, with modifications, for 2014 through 2018, inclusive of the requested capital investment amounts and an incentive mechanism providing the opportunity to earn above the allowed ROE. Within annual rate proceedings for 2015 through 2018, the customized IR Plan requires allowed revenues, and corresponding rates, to be updated annually for select items. The OEB also approved the adoption of a new approach for determining net salvage percentages to be included within EGD’s approved depreciation rates, as compared with the traditional approach previously employed. The new approach results in lower net salvage percentages for EGD, and therefore lowers depreciation rates and future removal and site restoration reserves. The customized IR Plan includes an earnings sharing mechanism, whereby any return over the allowed rate of return for a given year under the customized IR Plan will be shared equally with customers. For the year ended December 31, 2013, rates were set pursuant to an OEB approved settlement agreement and decision (the 2013 Settlement) related to its 2013 cost of service rate application. The 2013 Settlement retained the previous deemed equity level but provided for an increase in the allowed ROE. The 2013 Settlement further retained the flow-through nature of the cost of natural gas supply and several other cost categories and provided for OPEB and pension costs, determined on an accrual basis, to be recovered in rates. EGD’s after-tax rate of return on common equity embedded in rates was 9.3% for the year ended December 31, 2015 (2014 – 9.4%; 2013 – 8.9%) based on a 36% (2014 – 36%; 2013 – 36%) deemed common equity component of capital for regulatory purposes. Enbridge Gas New Brunswick Enbridge Gas New Brunswick is regulated by the EUB and currently sets tolls at either market-based or cost of service rates. Notes to the Consolidated Financial Statements 123
Financial Statement Effects Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities: December 31, 2015 2014 (millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines 1,15 Deferredincometaxes –907 2,15 Tolling deferrals –(39) 3 Recoverable income taxes 54 46 4 Pipeline future abandonment costs (4) – Gas Distribution 5 Deferredincometaxes 328 275 6 Purchased gas variance 129 673 7 Pension plans and OPEB 104 171 8 Constant dollar net salvage adjustment 42 37 9 Unabsorbed demand cost 66 14 10 Future removal and site restoration reserves (581) (562) 11 Site restoration clearance adjustment (193) (283) 12 Revenue adjustment –(52) 13 Transaction services deferral (9) (26) Sponsored Investments 1,15 Deferredincometaxes 1,048 15 4 Pipeline future abandonment costs (43) – 2,15 Tolling deferrals (39) – 14 Transportation revenue adjustments 11 36 1 The deferred income tax asset represents the regulatory of fset to deferred income tax liabilities that are expected to be recovered underflow-through income tax treatment. The recovery period depends on future reversal of temporary differences. 2 The tolling deferrals reflect net tax benefits expected to be refunded through future transportation tolls on Southern Lights Canada. The balance is expected to continue to accumulate through 2018 before being refunded through tolls. Tolling deferrals are not included in the rate base. 3 The recoverable income tax asset represents future revenues to be collected from shippers for Southern Lights US to recover federal income taxes payable on the equity component of AFUDC. The recovery period commenced in 2010 and is approximately 30 years. 4 The pipeline future abandonment costs liability results from amounts collected and set aside in accordance with the NEB’s LMCI to cover future abandonment costs for NEB regulated Canadian pipelines. Funds collected are included in Restricted long-term investments (Note 12). Concurrently, the Company reflects the future abandonment cost as a regulatory liability. The settlement of this balance will occur as pipeline abandonment costs are incurred. 5 The deferred income tax asset represents the regulatory offset to deferred income tax liabilities to the extent that deferred income taxes are expected to be recovered or refunded through regulator-approved rates. The recovery period depends on future temporary dif ferences. Deferred income taxes in Gas Distribution are excluded from the rate base and do not earn an ROE. 6 The purchased gas variance (PGVA) balance represents the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD has been granted OEB approval to refund this balance to, or to collect this balance from, customers on a rolling 12 month basis via the Quarterly Rate Adjustment Mechanism process. In May 2014, the OEB issued a decision allowing a portion of the PGVA as at June 30, 2014 to be recovered over a 24-month period from July 1, 2014 to June 30, 2016. 7 The pension plans and OPEB balances represent the regulatory of fset to pension plan and OPEB obligations to the extent the amounts are expected to be collected from customers in future rates. An OPEB balance of $89 million is being collected over a 20-year period that commenced in 2013. The balance at December 31, 2015 was $75 million (2014 – $84 million). The settlement period for the pension regulatory asset is not determinable. The balances are excluded from the rate base and do not earn an ROE. 8 The constant dollar net salvage adjustment represents the cumulative variance between the amount proposed for clearance and the actual amount cleared, relating specifically to the Site restoration adjustment. Any residual balance at the end of 2018 will be cleared in a post 2018 true up. 9 The unabsorbed demand cost deferral represents the actual cost consequences of unutilized transportation capacity contracted by EGD to meet increased requirements resulting from the Peak Gas Design Day Criteria (PGDDC). EGD updated its PGDDC in 2013 and 2014 and the impact of this update was phased in equally over the two years. 10 The future removal and site restoration reserves balance results from amounts collected from customers by certain businesses, with the approval of the regulator, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment. The balance represents the amount that has been collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur as future removal and site restoration costs are incurred. 11 The site restoration clearance adjustment represents the amount determined by the OEB of previously collected costs for future removal and site restoration that is considered to be in excess of future requirements and will be refunded to customers over the term of the customized IR Plan. This was a result of the OEB’s approval of the adoption of a new approach for determining net salvage percentages. The new approach resulted in lower depreciation rates and lower future removal and site restoration reserves. 12 The revenue adjustment represents the revenue variance between interim rates, which were in place from January 1, 2014 to September 30, 2014, and the final OEB approved 2014 rates, which were implemented on October 1, 2014, but ef fective January 1, 2014. The revenue adjustment balance is the 2014 OEB approved revenue adjustment amount that was refunded to customers in January 2015. 13 The transaction services deferral represents the customer portion of additional earnings generated from optimization of storage and pipeline capacity. The balance is expected to be refunded to customers in the following year. 14 The transportation revenue adjustments are the cumulative differences between actual expenses incurred and estimated expenses included in transportation tolls. Transportation revenue adjustments are not included in the rate base. The recovery period is approximately five years, commencing with tolls filed and in ef fect on January 1, 2015, and dependent on shipper throughput levels. 15 Ef fective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group within the Sponsored Investments segment as described under the Canadian Restructuring Plan (Note 1). Liquids Pipelines regulatory assets of $907 million and regulatory liabilities of $39 million as at December 31, 2014 have not been reclassified into the Sponsored Investments segment for presentation purposes. 124 Enbridge Inc. 2015 Annual Report
Other Items Affected by Rate Regulation Allowance for Funds Used During Construction and Other Capitalized Costs Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified. Operating Cost Capitalization With the approval of regulators, certain operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred. EGD entered into a consulting contract relating to asset management initiatives. The majority of the costs, primarily consulting fees, are being capitalized to gas mains in accordance with regulatory approval. At December 31, 2015, cumulative costs relating to this consulting contract of $179 million (2014 – $166 million) were included in Property, plant and equipment and are being depreciated over the average service life of 25 years. In the absence of rate regulation, some of these costs would be charged to earnings in the year incurred. 6. Acquisitions and Dispositions Acquisitions Midstream Business On February 27, 2015, EEP acquired the midstream business of New Gulf Resources, LLC (NGR) in Leon, Madison and Grimes Counties, Texas for $106 million (US$85 million) in cash and a contingent future payment of up to $21 million (US$17 million), through its partially-owned subsidiary, Midcoast Energy Partners, L.P. (MEP). The acquisition consisted of a natural gas gathering system that is in operation and is presented within the Sponsored Investments segment. Revenues and earnings of $2 million and nil, respectively, since the date of acquisition were recognized for the year ended December 31, 2015. If the acquisition had occurred on January 1, 2014, changes to revenues and earnings for the years ended December 31, 2015 and 2014 would have been nominal. The following purchase price allocation was completed by the Company: February 27, 2015 (millions of Canadian dollars) Fair value of net assets acquired: Property, plant and equipment 69 Intangible assets 40 109 Purchase price: Cash 106 1 Contingent consideration 3 1 The contingent future payment of up to US$17 million is dependent upon NGR’s ability to deliver specified volumes into MEP’s system over a five-year period. The fair value of the contingentfuture considerationatthe acquisitiondate andas atDecember31,2015 was $3million(US$2million) and$3million(US$2million),respectively. Magic Valley and Wildcat Wind Farms (Note 10) On December 31, 2014, Enbridge acquired an 80% controlling interest in Magic Valley, a wind farm located in Texas, and Wildcat, a wind farm located in Indiana, for cash consideration of $394 million (US$340 million). No revenue or earnings were recognized in the year ended December 31, 2014 as the wind farms were acquired on December 31, 2014. The wind farms are included within the Gas Pipelines, Processing and Energy Services segment. Notes to the Consolidated Financial Statements 125
If the acquisition had occurred on January 1, 2013, proforma consolidated revenues and earnings for the year ended December 31, 2014 would have increased by $64 million (US$58 million) and $8 million (US$7 million), respectively, and proforma consolidated revenues and earnings for the year ended December 31, 2013 would have increased by $44 million (US$43 million) and decreased by $2 million (US$2 million), respectively. The Company has completed its valuation of the acquired assets resulting in the following purchase price allocation. December 31, 2014 (millions of Canadian dollars) Fair valueofnetassetsacquired: Property, plant and equipment 747 Intangible assets 12 Other long-term liabilities (14) 1 Noncontrolling interests (Note 20) (351) 394 Purchase price: Cash 394 1 The fair value of the noncontrolling interests was determined using a combination of the implied purchasepricefortheremaining20% interest and discounted cashflow models. Other Acquisitions In November 2015, the Company acquired a 100% interest in the 103-megawatt (MW) New Creek Wind Project (New Creek) for cash consideration of $48 million (US$36 million), with $35 million (US$26 million) of the purchase price allocated to Property, plant and equipment and the remainder allocated to Intangible assets. New Creek is targeted to be in service in December 2016. In December 2014, the Company acquired an incremental 30% interest in the Massif du Sud Wind Project (Massif du Sud) for cash consideration of $102 million, bringing its total interest in the wind project to 80%. The Company acquired its original 50% interest in Massif du Sud in December 2012. The Company’s interest in Massif du Sud represents an undivided interest, with $97 million of the incremental purchase allocated to Property, plant and equipment and the remainder allocated to Intangible assets. Massif du Sud is operational. In October 2014, the Company acquired an incremental 17.5% interest in the Lac Alfred Wind Project (Lac Alfred) for cash consideration of $121 million, bringing its total interest in the wind project to 67.5%. The Company acquired its original 50% interest in Lac Alfred in December 2011. The Company’s interest in Lac Alfred represents an undivided interest, with $115 million of the incremental purchase allocated to Property, plant and equipment and the remainder allocated to Intangible assets. Lac Alfred is operational. In July 2013, the Company acquired a 50% undivided interest in the Saint Robert Bellarmin Wind Project (Saint Robert) for a purchase price of $106 million, of which $100 million was allocated to Property, plant and equipment, with the remainder allocated to Intangible assets. Saint Robert is operational. The Massif du Sud, Lac Alfred and Saint Robert wind projects were presented within the Gas Pipelines, Processing and Energy Services segment until August 31, 2015. Effective September 1, 2015, under the Canadian Restructuring Plan (Note 1), Enbridge transferred these wind projects to the Fund Group. These wind assets are reported within the Sponsored Investments segment from the date of the transfer. Other Dispositions In August 2015, the Company sold its 77.8% controlling interest in the Frontier Pipeline Company, which holds pipeline assets located in the midwest United States, to unrelated parties for gross proceeds of $112 million (US$85 million). A gain of $70 million (US$53 million) was presented within Other expense on the Consolidated Statements of Earnings. These amounts are included within the Liquids Pipelines segment. In May 2015, the Fund sold certain of its crude oil pipeline system assets to an unrelated party for gross proceeds of $26 million. A gain of $22 million was presented within Other expense on the Consolidated Statements of Earnings. 126 Enbridge Inc. 2015 Annual Report
In November 2014, the Company sold one of its non-core assets within Enbridge Offshore Pipelines (Offshore), which include pipeline facilities located in Louisiana, to an unrelated party for $7 million (US$7 million). A gain of $22 million (US$19 million) was presented within Other expense on the Consolidated Statements of Earnings. In July 2014, the Company sold a 35% equity interest in the Southern Access Extension Project, a pipeline project then under construction, to an unrelated party for gross proceeds of $73 million (US$68 million). As the fair value of the consideration received equalled the carrying value of the asset sold, no gain or loss was recognized on the sale (Note 11). In March 2014, the Company sold an Alternative and Emerging Technologies investment within the Corporate segment to an unrelated party for $19 million. A gain of $16 million was presented within Other expense on the Consolidated Statements of Earnings. In November 2013, EEP sold one of its non-core liquids assets, a storage facility in Kansas, to an unrelated party for $41 million (US$40 million). A gain of $18 million (US$17 million) was presented within Other expense on the Consolidated Statements of Earnings. 7. Accounts Receivable and Other December 31, 2015 2014 (millions of Canadian dollars) Unbilled revenues 2,476 2,218 Trade receivables 1,079 1,168 Taxes receivable 175 522 Regulatory assets 216 567 Short-term portion of derivative assets (Note 24) 791 568 Prepaid expenses and deposits 181 103 Current deferred income taxes (Note 25) 367 245 Dividends receivable 26 26 Other 164 129 Allowance for doubtful accounts (45) (42) 5,430 5,504 Pursuant to a Receivables Purchase Agreement (the Receivables Agreement) executed in 2013, certain trade and accrued receivables (the Receivables) have been sold by certain of EEP’s subsidiaries to an Enbridge wholly-owned special purpose entity (SPE). The Receivables owned by the SPE are not available to Enbridge except through its 100% ownership in such SPE. The Receivables Agreement provides for purchases to occur on a monthly basis through to December 2016, provided accumulated purchases net of collections do not exceed US$450 million at any one point. The value of trade and accrued receivables outstanding owned by the SPE totalled US$317 million ($439 million) and US$378 million ($439 million) as at December 31, 2015 and 2014, respectively. 8. Inventory December 31, 2015 2014 (millions of Canadian dollars) Natural gas 627 678 Crude oil 477 452 Other commodities 7 18 1,111 1,148 Notes to the Consolidated Financial Statements 127
9. Property, Plant and Equipment Weighted Average December 31, Depreciation Rate 2015 2014 (millions of Canadian dollars) 1,2 Liquids Pipelines Pipeline 2.9% 6,356 12,515 Pumping equipment, buildings, tanks and other 3.8% 1,464 7,715 Land and right-of-way 1.9% 228 520 Under construction –754 5,578 8,802 26,328 Accumulated depreciation (1,200) (4,312) 7,602 22,016 Gas Distribution Gasmains,servicesandother 3.0% 8,819 8,427 Land and right-of-way 1.0% 85 84 Under construction –902 352 9,806 8,863 Accumulated depreciation (2,379) (2,256) 7,427 6,607 1 Gas Pipelines, Processing and Energy Services Pipeline 4.2% 777 633 Wind turbines, solar panels and other 4.7% 2,162 2,371 Power transmission 1.8% 387 397 Canadian Midstream gas gathering and processing 2.9% 789 778 Land and right-of-way 3.2% 58 28 Under construction –933 1,172 5,106 5,379 Accumulated depreciation (643) (454) 4,463 4,925 1 Sponsored Investments Pipeline 2.6% 27,317 11,564 Pumping equipment, buildings, tanks and other 3.1% 17,008 7,806 Wind turbines, solar panels and other 4.0% 2,582 1,549 Land and right-of-way 2.5% 1,660 1,040 Under construction –5,330 2,126 53,897 24,085 Accumulated depreciation (9,087) (3,903) 44,810 20,182 Corporate Other 6.8% 184 80 Under construction –5 69 189 149 Accumulated depreciation (57) (49) 132 100 64,434 53,830 1 Effective September1,2015,Enbridge transferredits Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group with in the Sponsored Investments segment as described under the Canadian Restructuring Plan (Note 1).Liquids Pipelines Property, plant and equipment of $15,635 million and Gas Pipelines, Processing and Energy Services Property ,plant and equipment of $995 million as atDecember31,2014have not been reclassified in to the Sponsored Investments segment for presentation purposes. 2 InJuly2014,$62millionof Property, plant and equipment was disposed as part of the sale of a 35%equityinterestinthe Southern Access Extension Project. The remaining balance of $136millioninProperty,plantand equipment was reclassified to Long-term investments (Note 11). Depreciation expense for the year ended December 31, 2015 was $1,852 million (2014 – $1,461 million; 2013 – $1,282 million). 128 Enbridge Inc. 2015 Annual Report
Sponsored Investments Impairment The Company recorded impairment charges of $96 million, of which $80 million related to EEP’s Berthold rail facility due to contracts that have not been renewed beyond 2016. The remaining $16 million in impairment charges relate to EEP’s non-core Louisiana propylene pipeline asset following finalization of a contract restructuring with the primary customer. The impairment charges were based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cashflows, and were presented within Operating and administrative expense on the Consolidated Statements of Earnings. Discontinued Operations In March 2014, the Company completed the sale of certain of its Offshore assets located within the Stingray corridor to an unrelated third party for cash proceeds of $11 million (US$10 million), subject to working capital adjustments. The gain of $70 million (US$63 million), which resulted from the cash proceeds and the disposition of net liabilities held for sale of $59 million (US$53 million), is presented as Earnings from discontinued operations. The results of operations, including revenues of $4 million and $26 million and related cash flows, have also been presented as discontinued operations for the years ended December 31, 2014 and 2013, respectively. These amounts are included within the Gas Pipelines, Processing and Energy Services segment. 10. Variable Interest Entities The Company is required to consolidate a VIE in which the Company is the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. The Company assesses all aspects of its interest in the entity and uses its judgment when determining if the Company is the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. Gas Pipelines, Processing and Energy Services Magicat Holdco LLC Through its 80% controlling interest in Magicat Holdco LLC acquired on December 31, 2014, the Company is the primary beneficiary of the Magic Valley and Wildcat wind farms (Note 6). These wind farms are partially financed by tax equity investors and are considered VIEs by virtue of the Company’s voting rights, its power to direct the activities that most significantly impact the economic performance of the wind farms and the obligation to absorb losses. As at December 31, 2015, the Company’s investment in the Magic Valley and Wildcat wind farms was $394 million (2014 – $394 million). Keechi Holdings L.L.C. The Company initiated construction of the Keechi Wind Project on January 6, 2014. In January 2015, the tax equity investor financed 65% of the project and the wind farm was considered a VIE by virtue of the Company’s voting rights, its power to direct the activities that most significantly impact the economic performance of the wind farm and its obligation to absorb losses. Through its position as a managing member and having substantive participation rights in Keechi Wind, LLC the Company is considered the primary beneficiary of the Keechi Wind Project in Texas. As at December 31, 2015, the Company has contributed $204 million (2014 – $168 million) to Keechi Holdings L.L.C. At December 31, 2015, the Company’s consolidated balance sheet includes total assets of $1,147 million (2014 – $970 million) and total liabilities of $49 million (2014 – $44 million) related to the Magic Valley and Wildcat wind farms and the Keechi Creek Wind Project. The assets of these VIEs can only be used to settle their obligations. Enbridge does not have an obligation to provide financial support to these VIEs other than an indirect obligation, as prescribed by the terms of certain indemnities and guarantees, to pay the liabilities of the wind farms in the event of a default. The tax equity investors of these VIEs have priority in the allocation of distributions and tax deductions and credits generated by the project until it achieves a specified return. The Company has an option to purchase the tax equity investors’ interest in the project after it has achieved its target return at the greater of fair market value or an amount that would provide the tax equity investors with an internal rate of return specified in the agreements. Sponsored Investments Enbridge Income Fund The Fund is an unincorporated open-ended trust established by a trust indenture under the laws of the Province of Alberta and is considered a VIE by virtue of its capital structure. The Company is the primary beneficiary of the Fund through its combined 89.2% (2014 – 66.4%; 2013 – 67.3%) economic interest held indirectly through a common investment in ENF, a direct common interest in the Fund, a preferred unit investment in ECT, a direct common interest in Enbridge Income Partners GP Inc. and a direct common interest in EIPLP. At December 31, 2015, the Company’s direct common interest in the Fund was 49.2% (2014 – 11.9%; 2013 – 15.5%). As a result of the Canadian Restructuring Plan (Note 1), the Company received ordinary trust units of the Fund and common equity units in EIPLP as part of the consideration, increasing the Company’s economic interest in the Fund Group, as well as its direct common unit interest in the Fund. Enbridge also serves in the capacity of Manager of ENF and the Fund Group. Notes to the Consolidated Financial Statements 129
As at December 31, 2015, the Company’s consolidated balance sheet includes total assets of $113 million (2014 – $4,085 million) and total liabilities of $2,601 million (2014 – $3,213 million) related to the Fund. Certain of the Company’s subsidiaries provide unconditional guarantees of the Fund’s debt of $2,404 million (2014 – $2,544 million); however, the creditors of the Fund have no recourse to the general credit of the Company. Enbridge Commercial Trust As a result of the Canadian Restructuring Plan (Note 1), on September 1, 2015, ECT, previously a direct subsidiary of the Fund and consolidated by the Fund, amended its trust indenture to enable Enbridge to appoint the majority of the Trustees to ECT’s Board of Trustees resulting in the lack of decision making ability for the holders of the common trust units of ECT. As a result, ECT is considered to be a VIE and although Enbridge does not have a common equity interest in ECT, the Company is considered to be the primary beneficiary of ECT. Enbridge also serves in the capacity of Manager of ECT, as part of the Fund Group. At December 31, 2015, the Company’s consolidated balance sheet did not include any significant assets or liabilities related to ECT. 11. Long-Term Investments Ownership December 31, Interest 2015 2014 (millions of Canadian dollars) Equity Investments Liquids Pipelines Seaway Pipeline 50.0% 3,251 2,782 Southern Access Extension 65.0% 713 263 Other 30.0% – 75.0% 95 65 Gas Pipelines, Processing and Energy Services Aux Sable 42.7% – 50.0% 344 311 Vector Pipeline 60.0% 159 141 Offshore –various jointventures 22.0% – 74.3% 479 429 1 Rampion offshore wind project 24.9% 201 – Other 33.3% – 70.0% 13 12 Sponsored Investments Texas Express Pipeline 35.0% 515 442 2 Alliance Pipeline Canada and US 50.0% 436 374 Other 50.0% 54 67 Corporate Noverco Common Shares 38.9% –– Enbridge Rail (Philadelphia) L.L.C. 75.0% 142 – Other 19.0% – 49.99% 57 45 Other Long-Term Investments Corporate Noverco Preferred Shares 359 323 Enbridge Insurance (Barbados Oil) Limited 35 23 Enbridge (U.S.) Inc. 35 29 Other 120 102 7,008 5,408 1 OnNovember4,2015,Enbridge acquireda24.9% equityinterestinRampionOffshore WindLimited. 2 InNovember2014,Enbridge’s interestinAlliance Pipeline US was transferred to the Fund Group. As a result,$203millionof Long-term investments as atDecember31,2014were reclassified from Gas Pipelines, Processing and Energy Services to Sponsored Investments. Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees’ assets at the purchase date, which is comprised of $885 million (2014 – $742 million) in Goodwill and $568 million (2014 – $494 million) in amortizable assets. For the year ended December 31, 2015, dividends received from equity investments was $719 million (2014 – $564 million; 2013 – $685 million). 130 Enbridge Inc. 2015 Annual Report
Summarized combined financial information of the Company’s interest in unconsolidated equity investments is as follows: Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Revenues 1,557 1,790 1,212 Commodity costs (369) (661) (371) Operating and administrative expense (376) (444) (266) Depreciation and amortization (274) (232) (175) Other income/(expense) 4 (1) 4 Interest expense (67) (84) (74) Earnings before income taxes 475 368 330 December 31, 2015 2014 (millions of Canadian dollars) Current assets 389 472 Property, plant and equipment ,net 6,602 5,214 Deferred amounts and other assets 40 34 Intangible assets, net 64 77 Goodwill 885 742 Current liabilities (500) (712) Long-term debt (854) (811) Other long-term liabilities (167) (85) Net assets 6,459 4,931 Alliance Pipeline System Certain assets of the Alliance Pipeline System (Alliance System) are pledged as collateral to Alliance System lenders. Southern Access Extension Project On July 1, 2014, under an agreement with an unrelated third party, the Company sold a 35% equity interest in the Southern Access Extension Project (the Project). Prior to this sale, the subsidiary executing the Project was wholly-owned and consolidated within the Liquids Pipelines segment. The Company concluded that under the agreement, the purchaser of the 35% equity interest is entitled to substantive participating rights; however, the Company continues to exercise significant influence. As a result, effective July 1, 2014, the Company discontinued consolidation of the Project and recognized its remaining 65% equity interest as a long-term equity investment within the Liquids Pipelines segment. Noverco As at December 31, 2015, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2014 – 38.9%) of its common shares and an investment in preferred shares. The preferred shares are entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in 10 years plus a range of 4.3% to 4.4%. As at December 31, 2015, Noverco owned an approximate 3.6% (2014 – 3.6%; 2013 – 3.9%) reciprocal shareholding in common shares of Enbridge. Through secondary offerings, Noverco sold 15 million common shares in 2013 and a further 1.3 million common shares in 2014. The transactions were recognized as issuances of treasury stock on the Consolidated Statements of Changes in Equity. As a result of Noverco’s reciprocal shareholding in Enbridge common shares, the Company has an indirect pro-rata interest of 1.4% (2014 – 1.4%; 2013 – 1.5%) in its own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $83 million at December 31, 2015 (2014 – $83 million; 2013 – $86 million). Noverco records dividends paid by the Company as dividend income and the Company eliminates these dividends from its equity earnings of Noverco. The Company records its pro-rata share of dividends paid by the Company to Noverco as a reduction of dividends paid and an increase in the Company’s investment in Noverco. Notes to the Consolidated Financial Statements 131
Rampion Offshore Wind Project In November 2015, Enbridge announced the acquisition of a 24.9% interest in the 400 MW Rampion Offshore Wind Project (the Rampion project) in the United Kingdom (UK), located 13 kilometres (8 miles) off the UK Sussex coast at its nearest point. The Company’s total investment in the project through construction is expected to be approximately $750 million (Ł370 million). The Rampion project was developed and is being constructed by E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE (E.ON). Construction of the wind farm began in September 2015 and it is expected to be fully operational in 2018. The Rampion project is backed by revenues from the UK’s fixed price Renewable Obligation certificates program and a 15-year power purchase agreement. Under the terms of the purchase agreement, Enbridge became one of the three shareholders in Rampion Offshore Wind Limited which owns the Rampion project with the UK Green Investment Bank plc holding a 25% interest and E.ON retaining the balance of 50.1% interest. Enbridge’s portion of the costs incurred to date is approximately $201 million (Ł96.9 million) presented in Long-term investments. 12. Restricted Long-Term Investments Effective January 1, 2015, the Company began collecting and setting aside funds to cover future pipeline abandonment costs for all NEB regulated pipelines as a result of the NEB’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the NEB decision. The funds collected from shippers are reported within Transportation and other services revenues on the Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated Statements of Financial Position. Concurrently, the Company reflects the future abandonment cost as an increase to Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term liabilities on the Consolidated Statements of Financial Position. As at December 31, 2015, the Company had restricted long-term investments held in trust, invested in Canadian Treasury bonds, and are classified as held for sale and carried at fair value of $49 million (2014 – nil). As at December 31, 2015, the Company had estimated future abandonment costs of $48 million (2014 – nil) and restricted cash of nil (2014 – nil) related to LMCI. 13. Deferred Amounts and Other Assets December 31, 2015 2014 (millions of Canadian dollars) Regulatory assets (Note 5) 1,662 1,752 Long-term portion of derivative assets (Note 24) 373 199 Affiliate long-term notes receivable (Note 30) 152 183 Contractual receivables 432 382 Deferred financing costs 200 166 Other 490 526 3,309 3,208 As at December 31, 2015, deferred amounts of $406 million (2014 – $366 million) were subject to amortization and are presented net of accumulated amortization of $193 million (2014 – $189 million). Amortization expense for the year ended December 31, 2015 was $55 million (2014 – $38 million; 2013 – $34 million). 132 Enbridge Inc. 2015 Annual Report
14. Intangible Assets Weighted Average Accumulated December 31, 2015 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Software 11.6% 1,295 516 779 Natural gas supply opportunities 4.0% 484 122 362 Power purchase agreements 3.8% 94 11 83 Land leases, permits and other 4.2% 163 39 124 2,036 688 1,348 Weighted Average Accumulated December 31, 2014 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Software 12.9% 1,049 337 712 Natural gas supply opportunities 3.7% 340 83 257 Power purchase agreements 3.4% 113 11 102 Land leases, permits and other 4.0% 124 29 95 1,626 460 1,166 Total amortization expense for intangible assets was $158 million (2014 – $106 million; 2013 – $82 million) for the year ended December 31, 2015. The Company expects amortization expense for intangible assets for the years ending December 31, 2016 through 2020 of $180 million, $160 million, $144 million, $130 million and $117 million, respectively. 15. Goodwill Gas Pipelines, Processing Liquids Gas and Energy Sponsored Pipelines Distribution Services Investments Corporate Consolidated (millions of Canadian dollars) Balance at January 1, 2014 23 – 14 408 – 445 Foreign exchange and other 3 – 134 –38 Balance at December 31, 2014 26 – 15 442 – 483 Foreign exchange and other 5– 5 27 – 37 Impairment ––– (440) – (440) Balance at December 31, 2015 31 – 20 29 – 80 Sponsored Investments Impairment During the year ended December 31, 2015, the Company recorded an impairment charge of $440 million ($167 million after-tax attributable to Enbridge) related to EEP’s natural gas and NGL businesses, which EEP holds directly and indirectly through its partially-owned subsidiary, MEP. Due to a prolonged decline in commodity prices, reduction in producers’ expected drilling programs negatively impacted forecasted cash flows from EEP’s natural gas and NGL systems. This change in circumstance led to the completion of an impairment test, resulting in a full impairment of goodwill on EEP’s natural gas and NGL businesses. In performing the impairment assessment, EEP measured the fair value of its reporting units primarily by using a discounted cash flow analysis and it also considered overall market capitalization of its business, cash flow measurement data and other factors. EEP’s estimate of fair value required it to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of its reporting units. The Company did not recognize any goodwill impairment for the years ended December 31, 2014 and 2013. Notes to the Consolidated Financial Statements 133
16. Accounts Payable and Other December 31, 2015 2014 (millions of Canadian dollars) Operating accrued liabilities 3,028 2,939 Trade payables 561 414 Construction payables 750 746 Current derivative liabilities (Note 24) 1,945 1,020 Contractor holdbacks 299 368 Taxes payable 376 555 Security deposits 62 63 Asset retirement obligations (Note 19) 9 53 Other 321 286 7,351 6,444 17. Debt Weighted Average December 31, Interest Rate Maturity 2015 2014 (millions of Canadian dollars) 1 Liquids Pipelines Debentures –200 2,3 Medium-term notes 4.0% 2016 – 2040 1,439 4,557 Commercial paper and credit facility draws –163 4 Other 7 9 Gas Distribution Debentures 9.9% 2024 85 85 Medium-term notes 4.6% 2016 – 2050 3,603 3,033 Commercial paper and credit facility draws 599 939 1 Gas Pipelines, Processing and Energy Services 5 Promissory note –103 1 Sponsored Investments Debentures 8.2% 2024 200 – 6 Junior subordinated notes 8.1% 2067 554 464 7 Medium-term notes 4.3% 2016 – 2045 6,466 2,405 8 Senior notes 6.1% 2016 – 2045 7,958 4,815 9 Commercial paper and credit facility draws 4,012 2,614 4 Other 4 – Corporate 10 United States dollar term notes 3.3% 2016 – 2044 4,221 3,886 Medium-term notes 4.3% 2016 – 2064 5,698 6,048 11 Commercial paper and credit facility draws 7,332 6,182 12 Other (49) (35) Total debt 42,129 35,468 Current maturities (1,990) (1,004) 13 Short-term borrowings (599) (1,041) Long-term debt 39,540 33,423 1 Effective September1,2015,Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group with in the Sponsored Investments segment as described under the Canadian Restructuring Plan (Note 1). Liquids Pipelines Debt of $3,693 million and Gas Pipelines, Processing and Energy Services Debtof $103millionas atDecember31,2014has not been reclassified in to the Sponsored Investments segment for presentation purposes. 2 2015 – US$1,040 million (2014 – $3,323 million and US$1,064 million). 3 OnAugust18,2014,long-term private debtwas issuedfor$352millionandUS$1,061millionrelatedtoSouthernLights project financing. The proceeds were utilized to repay the construction credit facilities on a dollar-for-dollar basis. 4 Primarily capital lease obligations. 5 Anon-interest bearing demand promiss or y note that was paidonJanuary9,2015. 6 2015 – US$400 million (2014 – US$400 million). 7 Included in medium-termnotesis$100million withamaturitydateof2112. 8 2015 – US$5,750 million (2014 – US$4,150 million). 9 2015 – $1,346 million and US$1,926 million (2014 – $140 million and US$2,132 million). 10 2015 – US$3,050 million (2014 – US$3,350 million). 11 2015 – $4,168 million and US$2,287 million (2014 – $3,217 million and US$2,555 million). 12 Primarily debt discount. 13 Weightedaverage interestrate–0.8%(2014 –1.4%). 134 Enbridge Inc. 2015 Annual Report
For the years ending December 31, 2016 through 2020 debenture and term note maturities are $1,987 million, $2,639 million, $1,197 million, $1,883 million, $2,841 million, respectively, and $19,677 million thereafter. The Company’s debentures and term notes bear interest at fixed rates and interest obligations for the years ending December 31, 2016 through 2020 are $1,704 million, $1,599 million, $1,439 million, $1,246 million and $1,048 million, respectively. At December 31, 2015 and 2014, all debt was unsecured. Interest Expense Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Debentures and term notes 1,805 1,425 1,123 Commercial paper and credit facility draws 172 71 34 Southern Lights project financing –49 40 Capitalized (353) (416) (250) 1,624 1,129 947 Credit Facilities The following table provides details of the Company’s committed credit facilities at December 31, 2015 and December 31, 2014. 2015 2014 Total Total 1 December 31, Maturity Facilities Draws Available Facilities (millions of Canadian dollars) 2 Liquids Pipelines 2017 28 – 28 300 Gas Distribution 2017 – 2019 1,010 603 407 1,008 2 Sponsored Investments 2017 – 2020 9,224 4,089 5,135 4,531 Corporate 2017 – 2020 11,458 7,357 4,101 12,772 3 Total committed credit facilities 21,720 12,049 9,671 18,611 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 EffectiveSeptember1, 2015, Enbridge transferred its Canadian LiquidsPipelinesbusinessand certain Canadian renewableenergyassetstotheFund Group within theSponsored Investments segment as described under the Canadian Restructuring Plan (Note 1). LiquidsPipelinestotalfacilitiesof$300million asat December31, 2014 havenot been reclassified into the Sponsored Investments segment for presentation purposes. 3 OnAugust18,2014,long-term private debtwas issuedfor$352millionandUS$1,061millionrelatedtoSouthernLights projectfinancing.The proceeds were utilizedtorepay the construction credit facilities on a dollar-for-dollar basis. In addition to the committed credit facilities noted above, the Company also has $349 million (2014 – $361 million) of uncommitted demand credit facilities, of which $185 million (2014 – $80 million) was unutilized as at December 31, 2015. Credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and the Company has the option to extend the facilities, which are currently set to mature from 2017 to 2020. Commercial paper and credit facility draws, net of short-term borrowings, of $11,344 million (2014 – $8,960 million) are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt. The Company’s credit facility agreements include standard events of default and covenant provisions whereby accelerated repayment may be required if the Company were to default on payment or violate certain covenants. As at December 31, 2015, the Company was in compliance with all debt covenants. Notes to the Consolidated Financial Statements 135
18. Other Long-Term Liabilities December 31, 2015 2014 (millions of Canadian dollars) Regulatory liabilities (Note 5) 787 802 Derivative liabilities (Note 24) 3,950 2,078 Pension and OPEB liabilities (Note 26) 517 584 Asset retirement obligations (Note 19) 189 132 Environmental liabilities 89 70 Other 524 375 6,056 4,041 19. Asset Retirement Obligations The liability for the expected cash flows as recognized in the financial statements reflected discount rates ranging from 1.7% to 9.4% (2014 – 4.6% to 8.1%). A reconciliation of movements in the Company’s ARO is as follows: December 31, 2015 2014 (millions of Canadian dollars) Obligations at beginning of year 185 24 Liabilities incurred 2 177 Liabilities settled (45) (24) Change in estimate 30 –Foreign currency translation adjustment 21 5 Accretion expense 5 3 Obligations at end of year 198 185 Presented as follows: Accounts payable and other (Note 16) 9 53 Other long-term liabilities (Note 18) 189 132 198 185 In 2014, the Company recognized ARO in the amount of $177 million. Of this amount, $74 million related to the decommissioning of certain portions of Line 6B of EEP’s Lakehead System and $103 million related to the Canadian and United States portions of the Line 3 Replacement Program, which is targeted to be completed in 2019, whereby the Company will replace the existing Line 3 pipeline in Canada and the United States. 20. Noncontrolling Interests December 31, 2015 2014 (millions of Canadian dollars) Enbridge Energy Partners, L.P. 412 748 Enbridge Energy Management, L.L.C. (EEM) 203 790 EnbridgeGasDistributionInc.preferredshares 100 100 Renewable energy assets 561 351 Other 24 26 1,300 2,015 Enbridge Energy Partners, L.P. Noncontrolling interests in EEP represented the 80.0% (2014 – 79.5%) interest in EEP held by public unitholders, as well as interests of third parties in subsidiaries of EEP, including MEP. The net decrease in the carrying value of Noncontrolling interests in EEP was due to the transactions described below, which were partially offset by comprehensive income attributable to noncontrolling interests in EEP during the year ended December 31, 2015. On January 2, 2015, Enbridge transferred its 66.7% interest in the United States segment of the Alberta Clipper pipeline, held through a wholly-owned Enbridge subsidiary in the United States, 136 Enbridge Inc. 2015 Annual Report
to EEP for aggregate consideration of $1.1 billion (US$1 billion), consisting of approximately $814 million (US$694 million) of Class E equity units issued to Enbridge by EEP and the repayment of approximately $359 million (US$306 million) of indebtedness owed to Enbridge. Prior to the transfer, EEP owned the remaining 33.3% interest in the United States segment of the Alberta Clipper pipeline. The Class E units issued to Enbridge are entitled to the same distributions as the Class A units held by the public and are convertible into Class A units on a one-for-one basis at Enbridge’s option. The transaction applies to all distributions declared subsequent to the transfer. The Class E units are redeemable at EEP’s option after 30 years, if not converted by Enbridge prior to that time. The units have a liquidation preference equal to their notional value at December 23, 2014 of US$38.31 per unit, which was determined based on the trailing five-day volume-weighted average price of EEP’s Class A common units. EEP recorded the Class E units at fair value. As a result, the Company recorded a decrease in Noncontrolling interests of $304 million and increases in Additional paid-in capital and Deferred income tax liabilities of $218 million and $86 million, respectively. On March 13, 2015, EEP completed a listed share issuance. The Company participated only to the extent to maintain its 2% General Partner (GP) interest. The listed share issuance resulted in contributions of $366 million (US$289 million) from noncontrolling interest holders. Enbridge’s noncontrolling interests in EEP increased from 79.5% to 80.0% as a result of the listed share issuance. During the year ended December 31, 2015, EEP distributed $630 million (2014 – $504 million; 2013 – $463 million) to its noncontrolling interest holders in line with EEP’s objective to make quarterly distributions in an amount equal to its available cash, as defined in its partnership agreement and as approved by EEP’s Board of Directors. Effective July 1, 2014, Enbridge Energy Company, Inc., a wholly-owned subsidiary of Enbridge and the GP of EEP, entered into an equity restructuring transaction in which the Company irrevocably waived its right to receive cash distributions and allocations in excess of 2% in respect of its GP interest in the existing incentive distribution rights (IDR) in exchange for the issuance of (i) 66.1 million units of a new class of EEP units designated as Class D Units, and (ii) 1,000 units of a new class of EEP units designated as Incentive Distribution Units (IDU). The Class D Units entitle the Company to receive quarterly distributions equal to the distribution paid on EEP’s common units. This restructuring decreases the Company’s share of incremental cash distributions from 48% of all distributions in excess of US$0.495 per unit per quarter down to 23% of all distributions in excess of EEP’s current quarterly distribution of US$0.5435 per unit per quarter. The transaction applies to all distributions declared subsequent to the effective date. EEP recorded the Class D Units and IDU at fair value, which resulted in a reduction to the carrying amounts of the GP and limited partner capital accounts on a pro-rata basis. As a result, the Company recorded a decrease in Noncontrolling interests of $2,363 million inclusive of CTA and increases in Additional paid-in capital and Deferred income tax liabilities of $1,601 million and $762 million, respectively. In May 2013, EEP formed MEP as its wholly-owned subsidiary. Subsequently, on November 13, 2013, MEP completed its initial public offering of 18.5 million Class A common units representing limited partner interests and subsequently issued an additional 2.8 million Class A common units pursuant to an underwriters’ over-allotment option. MEP received proceeds of approximately $372 million (US$355 million). Upon finalization of the offering, MEP’s initial assets consisted of an approximate 39% ownership interest in EEP’s natural gas and NGL midstream business. EEP retained a 2% GP interest, an approximate 52% limited partner interest and all IDR in MEP, in addition to its 61% direct interest in the natural gas and NGL midstream assets. On July 1, 2014, EEP completed the sale of an additional 12.6% limited partnership interest in its natural gas and NGL midstream business to MEP for cash proceeds of $376 million (US$350 million). Upon finalization of this transaction, EEP continued to retain a 2% GP interest, an approximate 52% limited partner interest and all IDR in MEP. However, EEP’s direct interest in entities or partnerships holding the natural gas and NGL midstream operations reduced from 61% to 48%, with the remaining ownership held by MEP. Enbridge Energy Management, L.L.C. Noncontrolling interests in EEM represented the 88.3% (2014 – 88.3%) of the listed shares of EEM not held by the Company. During the year ended December 31, 2015, the decrease in the carrying value of Noncontrolling interests in EEM is primarily due to comprehensive loss attributable to noncontrolling interests in EEM, along with the fair value allocation attributable to EEM as a result of the Class E equity units issued to Enbridge by EEP as discussed above. During the year ended December 31, 2014, the decrease in the carrying value of Noncontrolling interests in EEM is due to the fair value allocation attributable to EEM as a result of the EEP equity restructuring as discussed above. During the year ended December 31, 2013, EEM completed a listed share issuance in which the Company did not participate and which resulted in contributions of $523 million from noncontrolling interest holders. Enbridge Gas Distribution Inc. The Company owns 100% of the outstanding common shares of EGD; however, the four million Cumulative Redeemable EGD Preferred Shares held by third parties are entitled to a claim on the assets of EGD prior to the common shareholder. The preferred shares have no fixed maturity date and have floating adjustable cash dividends that are payable at 80% of the prime rate. EGD may, at its option, redeem all or a portion of the outstanding shares for $25 per share plus all accrued and unpaid dividends to the redemption date. As at December 31, 2015, no preferred shares have been redeemed. Renewable Energy Assets Renewable energy assets include Magic Valley and Wildcat wind farms acquired on December 31, 2014 (Note 6) and Keechi Wind Project, a VIE (Note 10). During the year ended December 31, 2015, the net increase in the carrying value of Noncontrolling interests in Renewable energy assets is primarily due to contributions, net of distributions, received from noncontrolling interests, along with comprehensive income attributable to noncontrolling interests during the year ended December 31, 2015. Notes to the Consolidated Financial Statements 137
Redeemable Noncontrolling Interests Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Balance at beginning of year 2,249 1,053 1,000 Loss (3) (11) (24) Other comprehensive income/(loss), net of tax Change in unrealized gains/(loss) on cashflow hedges (7) (15) 4 Other comprehensive loss from equity investees (12) ––Reclassification to earnings of realized cashflow hedges 2 ––Reclassification to earnings of unrealized cashflow hedges 2 ––Change in foreign currency translation adjustment 18 5–Other comprehensive income/(loss) 3 (10) 4 Distributions to unitholders (114) (79) (72) Contributions from unitholders 670 323 92 Reversal of cumulative redemption value adjustment attributable to ECT preferred units (541) ––DilutionlossonEnbridgeIncomeFundissuanceoftrust units (355) ––Dilution loss on Enbridge Income Fund equity investment (132) ––Dilution gain on Enbridge Income Fund indirect equity investment 5 ––Redemption value adjustment 359 973 53 Balance at end of year 2,141 2,249 1,053 Redeemable noncontrolling interests in the Fund at December 31, 2015 represented 40.7% (2014 – 70.6%; 2013 – 68.6%) of interests in the Fund’s trust units that are held by third parties. In September 2015, Enbridge’s unitholdings in the Fund increased upon closing of the Canadian Restructuring Plan (Note 1), resulting in a decrease in redeemable noncontrolling interests from 70.6% to 34.3%. Upon closing of the Canadian Restructuring Plan, ECT, an equity investment of the Fund, reclassified its Preferred Units from mezzanine equity to liabilities. Accordingly, ECT reduced the recorded redemption value of its Preferred Units to their aggregate par value, resulting in an increase to the Fund’s equity investment in ECT. This resulted in an adjustment to redeemable noncontrolling interests of approximately $541 million. Upon closing of the Canadian Restructuring Plan, EIPLP, an indirect equity investment of the Fund, issues Temporary Performance Distribution Rights (TPDR) to Enbridge each month in the form of Class D units of EIPLP. The Class D unitholders receive a distribution each month equal to the per unit amount paid on Class C units of EIPLP, but to be paid in kind in additional Class D units. The issuances of TPDR and additional Class D units result in a dilution gain for the Fund’s indirect equity investment in EIPLP. A dilution gain for redeemable noncontrolling interests of $5 million was recorded for the year ended December 31, 2015. In November 2015, ENF completed a bought deal public offering of common shares for approximately $700 million and issued additional common shares to Enbridge for approximately $174 million in order for Enbridge to maintain its 19.9% in ENF. ENF used the aggregate proceeds of $874 million to subscribe for additional trust units of the Fund. Enbridge did not participate in this offering, resulting in an increase in redeemable noncontrolling interests from 34.3% to 40.7%. This resulted in contributions of $670 million, net of share issue costs, from redeemable noncontrolling interest holders and a dilution loss for redeemable noncontrolling interests of $355 million for the year ended December 31, 2015. In November 2015, the Fund used the aggregate proceeds of $874 million from the issuance of trust units to ENF to purchase additional common units of ECT, and ECT used the aggregate proceeds of $874 million to purchase additional Class A units of EIPLP, resulting in a dilution loss for ECT. This dilution loss resulted in a dilution loss for Fund’s equity investment in ECT and a dilution loss for redeemable noncontrolling interests of $132 million for the year ended December 31, 2015. In November 2014, the Fund Group acquired Enbridge’s 50% interest in Alliance Pipeline US and subscribed for and purchased Class A units of Enbridge’s subsidiaries that indirectly own the Canadian and United States segments of the Southern Lights Pipeline for a total consideration of approximately $1.8 billion, including $421 million in cash, $878 million in the form of a long-term note payable by the Fund, bearing interest of 5.5% per annum and was fully repaid at December 31, 2015, and $461 million 138 Enbridge Inc. 2015 Annual Report
in the form of preferred units of ECT, which at the time of the transfer was a subsidiary of the Fund. To fund the cash component of the consideration, the Fund issued approximately $421 million of trust units to ENF. To purchase the trust units from the Fund, ENF completed a bought deal public offering of common shares for approximately $337 million and issued additional common shares to Enbridge for approximately $84 million in order for Enbridge to maintain its 19.9% interest in ENF. As a result of the transfer, redeemable noncontrolling interests in the Fund increased from 68.6% to 70.6% and contributions of $323 million, net of share issue costs, were received from redeemable noncontrolling interest holders. During the year ended December 31, 2013, the Fund completed a unit issuance in which the Company did not participate, resulting in an increase in the redeemable noncontrolling interests from 67.7% to 68.6%. This resulted in contributions of $92 million from redeemable noncontrolling interest holders. Distributions to noncontrolling unitholders were made on a monthly basis for the years ended December 31, 2015, 2014 and 2013 in line with the Fund’s objective of distributing a high proportion of its cash available for distribution, as approved by its Board of Trustees. 21. Share Capital The authorized share capital of the Company consists of an unlimited number of common shares with no par value and an unlimited number of preference shares. Common Shares 2015 2014 2013 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of common shares in millions) Balance at beginning of year 852 6,669 831 5,744 805 4,732 1 Common shares issued ––9446 13 582 Dividend Reinvestment and Share Purchase Plan (DRIP) 12 646 9428 8 361 Sharesissuedon exerciseofstockoptions 476 351 5 69 Balance at end of year 868 7,391 852 6,669 831 5,744 1 Grossproceeds – nil(2014 –$460million;2013 –$600million);net issuancecosts – nil(2014 –$14 million;2013 –$18 million). Preference Shares 2015 2014 2013 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of preference shares in millions) Preference Shares, Series A 5125 5 125 5 125 Preference Shares, Series B 20 500 20 500 20 500 Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 20 500 20 500 20 500 Preference Shares, Series H 14 350 14 350 14 350 Preference Shares, Series J 8199 8199 8199 Preference Shares, Series L 16 411 16 411 16 411 Preference Shares, Series N 18 450 18 450 18 450 Preference Shares, Series P 16 400 16400 16400 Preference Shares, Series R 16 400 16400 16400 Preference Shares, Series 1 16 411 16 411 16 411 Preference Shares, Series 3 24 600 24 600 24 600 Preference Shares, Series 5 8206 8 206 8 206 Preference Shares, Series 7 10 250 10 250 10 250 Preference Shares, Series 9 11 275 11 275 – –Preference Shares, Series 11 20 500 20 500 – –Preference Shares, Series 13 14 350 14 350 – –Preference Shares, Series 15 11 275 11 275 – –Issuance costs (137) (137) (111) Balance at end of period 6,515 6,515 5,141 Notes to the Consolidated Financial Statements 139
Characteristics of the preference shares are as follows: Initial Per Share Base Redemption and Right to ?1 ?2 2,3 3,4 Yield Dividend Redemption Value Conversion Option Date Convert Into (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.5% $1.375 $25 – – Preference Shares, Series B 4.0% $1.000 $25 June 1, 2017 Series C Preference Shares, Series D 4.0% $1.000 $25 March 1, 2018 Series E Preference Shares, Series F 4.0% $1.000 $25 June 1, 2018 Series G Preference Shares, Series H 4.0% $1.000 $25 September 1, 2018 Series I Preference Shares, Series J 4.0% US$1.000 US$25 June 1, 2017 Series K Preference Shares, Series L 4.0% US$1.000 US$25 September 1, 2017 Series M Preference Shares, Series N 4.0% $1.000 $25 December 1, 2018 Series O Preference Shares, Series P 4.0% $1.000 $25 March 1, 2019 Series Q Preference Shares, Series R 4.0% $1.000 $25 June 1, 2019 Series S Preference Shares, Series 1 4.0% US$1.000 US$25 June 1, 2018 Series 2 Preference Shares, Series 3 4.0% $1.000 $25 September 1, 2019 Series 4 Preference Shares, Series 5 4.4% US$1.100 US$25 March 1, 2019 Series 6 Preference Shares, Series 7 4.4% $1.100 $25 March 1, 2019 Series 8 Preference Shares, Series 9 4.4% $1.100 $25 December 1, 2019 Series 10 Preference Shares, Series 11 4.4% $1.100 $25 March1,2020 Series12 Preference Shares, Series 13 4.4% $1.100 $25 June 1, 2020 Series 14 Preference Shares, Series 15 4.4% $1.100 $25 September 1, 2020 Series 16 1 Theholderisentitled toreceiveafixed, cumulative, quarterlypreferentialdividend peryear, asdeclared bytheBoard ofDirectorsoftheCompany. 2 PreferenceShares, SeriesAmayberedeemed anytimeat theCompany’soption. For allotherseriesofPreferenceShares, theCompany, mayat itsoption, redeemallora portion oftheoutstandingPreferenceSharesfor theBaseRedemption Valuepershareplusallaccrued and unpaid dividendson theRedemption Option Dateand on everyfifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the ConversionOptionDate andeveryfifthanniversarythereafteratanascribedissue price equal tothe Base RedemptionValue. 4 Holderswillbe entitled toreceivequarterlyfloatingratecumulativedividends pershareatarateequalto:$25x (numberofdaysin quarter/365)x (90-dayGovernment ofCanada treasurybill rate+2.4%(Series C),2.4%(Series E),2.5%(Series G),2.1%(Series I),2.7%(SeriesO),2.5%(Series Q),2.5%(Series S),2.4%(Series 4),2.6%(Series 8),2.7%(Series 10),2.6%(Series 12),2.7%(Series 14)or2.7%(Series 16)); orUS$25x(numberof days inquarter/365) x (three-monthUnitedStatesGovernmenttreasurybill rate+3.1%(Series K), 3.2%(Series M),3.1%(Series 2)or2.8%(Series 6)). Earnings Per Common Share Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by the Company’s pro-rata weighted average interest in its own common shares of 12 million (2014 – 12 million; 2013 – 15 million) resulting from the Company’s reciprocal investment in Noverco. The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period. December 31, 2015 2014 2013 (number of common shares in millions) Weighted average shares outstanding 847 829 806 Effect ofdilutiveoptions 11 11 11 Diluted weighted average shares outstanding 858 840 817 For the year ended December 31, 2015, 7,960,028 anti-dilutive stock options (2014 – 6,058,580; 2013 – 6,327,500) with a weighted average exercise price of $55.81 (2014 – $48.78; 2013 – $44.85) were excluded from the diluted earnings per common share calculation. Dividend Reinvestment and Share Purchase Plan Under the DRIP, registered shareholders may reinvest dividends in common shares of the Company and make additional optional cash payments to purchase common shares, free of brokerage or other charges. Participants in the Company’s DRIP receive a 2% discount on the purchase of common shares with reinvested dividends. 140 Enbridge Inc. 2015 Annual Report
Shareholder Rights Plan The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any takeover offer for the Company. Rights issued under the plan become exercisable when a person and any related parties acquires or announces its intention to acquire 20% or more of the Company’s outstanding common shares without complying with certain provisions set out in the plan or without approval of the Company’s Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase common shares of the Company at a 50% discount to the market price at that time. 22. Stock Option and Stock Unit Plans The Company maintains four long-term incentive compensation plans: the ISO Plan, the PSO Plan, the PSU Plan and the RSU Plan. A maximum of 60 million common shares were reserved for issuance under the 2002 ISO plan, of which 50 million have been issued to date. A further 71 million common shares have been reserved for issuance for the 2007 ISO and PSO plans, of which 11 million have been exercised and issued from treasury to date. The PSU and RSU plans grant notional units as if a unit was one Enbridge common share and are payable in cash. Incentive Stock Options Key employees are granted ISO to purchase common shares at the market price on the grant date. ISO vest in equal annual instalments over a four-year period and expire 10 years after the issue date. Weighted Average Weighted Remaining Aggregate Average Contractual Intrinsic December 31, 2015 Number Exercise Price Life (years) Value (options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 31,330 34.97 Options granted 5,852 59.14 1 Options exercised (4,224) 26.61 Options cancelled or expired (170) 44.87 Options outstanding at end of year 32,788 40.31 6.3 525 2 Options vested at end of year 18,297 31.66 4.8 451 1 The total intrinsic value of ISOexercisedduring the yearendedDecember31,2015 was $126million(2014–$117 million; 2013–$98million) andcashreceivedonexercise was $43 million (2014 – $37 million; 2013 – $24 million). 2 Thetotalfairvalueofoptionsvested undertheISO Plan duringtheyearended December31, 2015was$34 million (2014–$26 million;2013–$22 million). Weighted average assumptions used to determine the fair value of ISO granted using the Black-Scholes- Merton option pricing model are as follows: Year ended December 31, 2015 2014 2013 1 Fairvalue peroption (Canadian dollars) 6.48 5.53 5.27 Valuation assumptions 2 Expected option term (years) 5 55 3 Expected volatility 19.9% 16.9% 17.4% 4 Expected dividend yield 3.2% 2.9% 2.8% 5 Risk-free interest rate 0.9% 1.6% 1.2% 1 Optionsgranted toUnited Statesemployeesarebased on New YorkStockExchangeprices. Theoption valueand assumptionsshown arebased onaweighted averageofthe United Statesand theCanadian options. Thefairvaluesperoption were$6.22 (2014–$5.45;2013–$5.15) forCanadian employeesand US$6.16 (2014–US$5.35;2013–US$5.63) for United States employees. 2 Theexpected option termissix yearsbased on historicalexercisepracticeand threeyearsforretirement eligibleemployees. 3 Expectedvolatilityis determinedwithreference tohistoric dailyshare price volatilityandconsiderationof the impliedvolatilityobservable incall optionvalues nearthe grantdate. 4 The expecteddividendyieldis the currentannual dividendatthe grantdate dividedbythe currentstock price. 5 Therisk-freeinterest rateisbased on theGovernment ofCanada’sCanadian Bond Yieldsand theUnited StatesTreasuryBond Yields. Compensation expense recorded for the year ended December 31, 2015 for ISO was $35 million (2014 – $29 million; 2013 – $27 million). At December 31, 2015, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the ISO Plan was $47 million. The cost is expected to be fully recognized over a weighted average period of approximately two years. Notes to the Consolidated Financial Statements 141
Performance Stock Options PSO are granted to executive officers and become exercisable when both performance targets and time vesting requirements have been met. PSO were granted on August 15, 2007, February 19, 2008, August 15, 2012 and March 13, 2014 under the 2007 plan. All performance targets for the 2007 and 2008 grants have been met. The time vesting requirements were fulfilled evenly over a five-year period ending on August 15, 2012 with the options being exercisable until August 15, 2015. Time vesting requirements for the 2012 grant will be fulfilled evenly over a five-year term, ending August 15, 2017. The 2012 grant’s performance targets are based on the Company’s share price and must be met by February 15, 2019 or the options expire. As at December 31, 2015, all performance targets have been met and the options are exercisable until August 15, 2020. Time vesting requirements for the 2014 grant will be fulfilled evenly over a four-year term, ending March 13, 2018. The 2014 grant’s performance targets are based on the Company’s share price and must be met by February 15, 2019 or the options expire. As at December 31, 2015, all performance targets have been met and the options are exercisable until August 15, 2020. Weighted Average Weighted Remaining Aggregate Average Contractual Intrinsic December 31, 2015 Number Exercise Price Life (years) Value (options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 4,511 35.97 Options granted ––1 Options exercised (830) 19.44 Options cancelled or expired (464) 39.34 Options outstanding at end of year 3,217 39.75 3.9 53 2 Options vested at end of year 2,307 39.48 3.7 39 1 ThetotalintrinsicvalueofPSO exercised duringtheyearended December31, 2015was$43 million (2014–nil;2013 – $62 million)and cash received on exercisewas$13 million (2014–nil;2013–$28 million). 2 Thetotalfairvalueofoptionsvested underthePSO Plan duringtheyearended December31, 2015was$6 million (2014 –$5million;2013–nil). Assumptions used to determine the fair value of PSO granted using the Bloomberg barrier option valuation model are as follows: Year ended December 31, 2014 Fair value per option (Canadian dollars) 5.77 Valuation assumptions 1 Expected option term (years) 6.5 2 Expected volatility 15.0% 3 Expected dividend yield 2.8% 4 Risk-free interest rate 1.7% 1 Theexpected option termisbasedon historicalexercisepractice. 2 Expected volatility is determined with reference to historic daily share price volatility. 3 The expecteddividendyieldis the currentannual dividendatthe grantdate dividedbythe currentstock price. 4 Therisk-freeinterest rateisbased on theGovernment ofCanada’sCanadian Bond Yields. Compensation expense recorded for the year ended December 31, 2015 for PSO was $3 million (2014 – $3 million; 2013 – $3 million). At December 31, 2015, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the PSO Plan was $5 million. The cost is expected to be fully recognized over a weighted average period of approximately two years. 142 Enbridge Inc. 2015 Annual Report
Performance Stock Units The Company has a PSU Plan for executives where cash awards are paid following a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by the Company’s weighted average share price for 20 days prior to the maturity of the grant and by a performance multiplier. The performance multiplier ranges from zero, if the Company’s performance fails to meet threshold performance levels, to a maximum of two if the Company performs within the highest range of its performance targets. The performance multiplier is derived through a calculation of the Company’s price/earnings ratio relative to a specified peer group of companies and the Company’s earnings per share, adjusted for unusual, non-operating or non-recurring items, relative to targets established at the time of grant. To calculate the 2015 expense, multipliers of two, were used for each of the 2013, 2014 and 2015 PSU grants. Weighted Average Remaining Aggregate Contractual Intrinsic December 31, 2015 Number Life (years) Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 555 Units granted 244 Units cancelled (9) 1 Units matured (282) Dividend reinvestment 28 Units outstanding at end of year 536 1.5 47 1 The total amount paid during the year ended December 31, 2015 for PSU was $35 million (2014 – $36 million; 2013 – $48 million). Compensation expense recorded for the year ended December 31, 2015 for PSU was $12 million (2014 – $40 million; 2013 – $25 million). As at December 31, 2015, unrecognized compensation expense related to non-vested units granted under the PSU Plan was $28 million and is expected to be fully recognized over a weighted average period of approximately two years. Restricted Stock Units Enbridge has a RSU Plan where cash awards are paid to certain non-executive employees of the Company following a 35-month maturity period. RSU holders receive cash equal to the Company’s weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date. Weighted Average Remaining Aggregate Contractual Intrinsic December 31, 2015 Number Life (years) Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 1,959 Units granted 854 Units cancelled (101) 1 Units matured (904) Dividend reinvestment 98 Units outstanding at end of year 1,906 1.4 88 1 The total amount paid during the year ended December 31, 2015 for RSU was $45 million (2014 – $45 million; 2013 – $41 million). Compensation expense recorded for the year ended December 31, 2015 for RSU was $47 million (2014 – $44 million; 2013 – $36 million). As at December 31, 2015, unrecognized compensation expense related to non-vested units granted under the RSU Plan was $64 million and is expected to be fully recognized over a weighted average period of approximately one year. Notes to the Consolidated Financial Statements 143
23. Components of Accumulated Other Comprehensive Income/(Loss) Changes in AOCI attributable to Enbridge common shareholders for the years ended December 31, 2015, 2014 and 2013, are as follows: Pension Net Cumulative and OPEB Cash Flow Investment Translation Equity Amortization Hedges Hedges Adjustment Investees Adjustment Total (millions of Canadian dollars) Balance at January 1, 2015 (488) 108 309 (5) (359) (435) Other comprehensive income/(loss) retained in AOCI 73 (952) 3,056 47 65 2,289 Other comprehensive gains/(loss) reclassified to earnings 1 Interest rate contracts (34) – – – – (34) 2 Commodity contracts (11) – – – – (11) 3 Foreign exchange contracts 7–––– 7 4 Other contracts 26 – – – – 26 Amortization of pension and OPEB actuarial loss 5 and prior service costs –––– 32 32 Other comprehensive loss reclassified to earnings of derecognized cashflow hedges (Note 24) (338) – – – – (338) (277) (952) 3,056 47 97 1,971 Tax impact Income tax on amounts retained in AOCI (29) 49 – (5) (14) 1 Income tax on amounts reclassified to earnings 15 – – – (11) 4 Income tax on amounts reclassified to earnings of derecognized cashflow hedges (Note 24) 91 – – – – 91 77 49 – (5) (25) 96 Balance at December 31, 2015 (688) (795) 3,365 37 (287) 1,632 Pension Net Cumulative and OPEB Cash Flow Investment Translation Equity Amortization Hedges Hedges Adjustment Investees Adjustment Total (millions of Canadian dollars) Balance at January 1, 2014 (1) 378 (778) (15) (183) (599) Other comprehensive income/(loss) retained in AOCI (857) (301) 1,087 10 (265) (326) Other comprehensive gains/(loss) reclassified to earnings 1 Interest rate contracts 201 – – – – 201 2 Commodity contracts (2) – – – – (2) 3 Foreign exchange contracts 8–––– 8 4 Other contracts (23) – – – – (23) Amortization of pension and OPEB actuarial loss 5 and prior service costs –––– 18 18 (673) (301) 1,087 10 (247) (124) Tax impact Income tax on amounts retained in AOCI 231 31 – – 74 336 Income tax on amounts reclassified to earnings (45) – – – (3) (48) 186 31 – – 71 288 Balance at December 31, 2014 (488) 108 309 (5) (359) (435) 144 Enbridge Inc. 2015 Annual Report
Pension Net Cumulative and OPEB Cash Flow Investment Translation Equity Amortization Hedges Hedges Adjustment Investees Adjustment Total (millions of Canadian dollars) Balance at January 1, 2013 (621) 474 (1,265) (26) (324) (1,762) Other comprehensive income/(loss) retained in AOCI 707 (111) 487 11 165 1,259 Other comprehensive gains/(loss) reclassified to earnings 1 Interest rate contracts 134 –––– 134 2 Commodity contracts (1) – – – – (1) 3 Foreign exchange contracts (8) – – – – (8) Amortization of pension and OPEB actuarial loss 5 and prior service costs –––– 36 36 832 (111) 487 11 201 1,420 Tax impact Income tax on amounts retained in AOCI (176) 15 – – (51) (212) Income tax on amounts reclassified to earnings (36) ––– (9) (45) (212) 15 – – (60) (257) Balance at December 31, 2013 (1) 378 (778) (15) (183) (599) 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Commodity costs in the Consolidated Statements of Earnings. 3 Reported within Other expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 These components are includedinthe computationof netperiodic pensioncosts andare reportedwithinOperating andadministrative expense inthe ConsolidatedStatements of Earnings. 24. Risk Management and Financial Instruments Market Risk The Company’s earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price (collectively, market risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which the Company is exposed and the risk management instruments used to mitigate them. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk The Company generates certain revenues, incurs expenses, and holds a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, the Company’s earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. The Company has implemented a policy whereby, at a minimum, it hedges a level of foreign currency denominated earnings exposures over a five year forecast horizon. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. The Company hedges certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt. Interest Rate Risk The Company’s earnings and cash flows are exposed to short term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense through 2019 via execution of floating to fixed interest rate swaps with an average swap rate of 2.0%. Notes to the Consolidated Financial Statements 145
The Company’s earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to significantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances through 2019 via execution of floating to fixed interest rate swaps with an average swap rate of 3.4%. The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt within its Board of Directors approved policy limit of a maximum of 25%floating rate debt as a percentage of total debt outstanding. The Company uses primarily qualifying derivative instruments to manage interest rate risk. Commodity Price Risk The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of its ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. The Company employs financial derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk. Equity Price Risk Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, RSU. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk. Total Derivative Instruments The following table summarizes the Consolidated Statements of Financial Position location and carrying value of the Company’s derivative instruments. The Company did not have any outstanding fair value hedges as at December 31, 2015 or 2014. The Company generally has a policy of entering into individual International Swaps and Derivatives Association, Inc. (ISDA) agreements, or other similar derivative agreements, with the majority of its derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit event, and would reduce the Company’s credit risk exposure on derivative asset positions outstanding with the counterparties in these particular circumstances. The following table also summarizes the maximum potential settlement amount in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. 146 Enbridge Inc. 2015 Annual Report
Derivative Derivative Instruments Total Gross Instruments Used as Net Non–Qualifying Derivative Amounts Total Net Used as Cash Investment Derivative Instruments Available Derivative December 31, 2015 Flow Hedges Hedges Instruments as Presented for Offset Instruments (millions of Canadian dollars) Accounts receivable and other (Note 7) Foreign exchange contracts 622 10 (3) 7 Interest rate contracts 2–– 2 (2) –Commodity contracts 7– 772 779 (211) 568 Other contracts –––– – – 15 2 774 791 (216) 575 Deferred amounts and other assets (Note 13) Foreign exchange contracts 114 4 10 128 (127) 1 Interest rate contracts 18 – – 18 (14) 4 Commodity contracts 7 – 220 227 (77) 150 Other contracts –––– – –139 4 230 373 (218) 155 Accounts payable and other (Note 16) Foreign exchange contracts (1) (106) (765) (872) 3 (869) Interest rate contracts (379) – (185) (564) 2 (562) Commodity contracts – – (501) (501) 194 (307) Other contracts (2) – (6) (8) – (8) (382) (106) (1,457) (1,945) 199 (1,746) Other long-term liabilities (Note 18) Foreign exchange contracts – (252) (2,796) (3,048) 127 (2,921) Interest rate contracts (405) – (224) (629) 14 (615) Commodity contracts – – (260) (260) 77 (183) Other contracts (8) – (5) (13) – (13) (413) (252) (3,285) (3,950) 218 (3,732) Total net derivative asset/(liability) Foreign exchange contracts 119 (352) (3,549) (3,782) – (3,782) Interest rate contracts (764) – (409) (1,173) – (1,173) 1 Commodity contracts 14 – 231 245 (17) 228 Other contracts (10) – (11) (21) – (21) (641) (352) (3,738) (4,731) (17) (4,748) Notes to the Consolidated Financial Statements 147
Derivative Derivative Instruments Total Gross Instruments Used as Net Non–Qualifying Derivative Amounts Total Net Used as Cash Investment Derivative Instruments Available Derivative December 31, 2014 Flow Hedges Hedges Instruments as Presented for Offset Instruments (millions of Canadian dollars) Accounts receivable and other (Note 7) Foreign exchange contracts 373 13 (13) –Interest rate contracts 8–– 8 (7) 1 Commodity contracts 34 – 501 535 (130) 405 Other contracts 4 – 8 12 – 12 49 7 512 568 (150) 418 Deferred amounts and other assets (Note 13) Foreign exchange contracts 33 18 – 51 (51) –Interest rate contracts 5–– 5 (5) –Commodity contracts 17 – 118 135 (43) 92 Other contracts 5– 3 8 – 8 60 18 121 199 (99) 100 Accounts payable and other (Note 16) Foreign exchange contracts (3) (80) (218) (301) 13 (288) Interest rate contracts (438) – – (438) 7 (431) Commodity contracts – – (281) (281) 97 (184) (441) (80) (499) (1,020) 117 (903) Other long-term liabilities (Note 18) Foreign exchange contracts – (49) (1,147) (1,196) 51 (1,145) Interest rate contracts (576) – – (576) 5 (571) Commodity contracts – – (306) (306) 43 (263) (576) (49) (1,453) (2,078) 99 (1,979) Total net derivative asset/(liability) Foreign exchange contracts 33 (104) (1,362) (1,433) – (1,433) Interest rate contracts (1,001) – – (1,001) – (1,001) 1 Commodity contracts 51 – 32 83 (33) 50 Other contracts 9 – 11 20 – 20 (908) (104) (1,319) (2,331) (33) (2,364) 1 Amount available for offset includes $17 million (2014 – $33 million) of cash collateral. 148 Enbridge Inc. 2015 Annual Report
The following table summarizes the maturity and notional principal or quantity outstanding related to the Company’s derivative instruments. December 31, 2015 2016 2017 2018 2019 2020 Thereafter Foreign exchange contracts – United States dollar forwards–purchase (millions of United States dollars) 172 413222 –Foreign exchange contracts – United States dollar forwards–sell (millions of United States dollars) 3,059 3,213 3,133 2,630 2,303 787 Foreign exchange contracts – GBP forwards – purchase (millions of GBP) 70 77 6–––Foreignexchange contracts–GBP forwards–sell (millions of GBP) ––– 89 25 144 Interest ratecontracts–short-termborrowings (millions of Canadian dollars) 8,382 7,604 4,536 1,574 156 406 Interest ratecontracts–long-termdebt (millions of Canadian dollars) 4,291 3,371 1,960 773 – –Equity contracts (millions of Canadian dollars) 51 48––––Commodity contracts – natural gas (billions of cubic feet) (126) (209) (17) 2 1 – Commodity contracts – crude oil (millions of barrels) (6) (17) (9) –––Commodity contracts – NGL (millions of barrels) (5) 1––––Commodity contracts – power (megawatt hours (MWH)) 40 40 30 31 35 (35) December 31, 2014 2015 2016 2017 2018 2019 Thereafter Foreign exchange contracts – United States dollar forwards–purchase (millions of United States dollars) 240 25 4132 22 Foreign exchange contracts – United States dollar forwards–sell (millions of United States dollars) 3,203 2,470 2,832 3,100 2,441 2,901 Foreign exchange contracts – Euro forwards – purchase (millions of Euros) 15 ––––– Interest ratecontracts–short-termborrowings (millions of Canadian dollars) 5,767 5,486 4,851 3,529 222 469 Interest ratecontracts–long-termdebt (millions of Canadian dollars) 3,528 1,762 2,470 1,176 – – Equity contracts (millions of Canadian dollars) 41 51–––– Commodity contracts – natural gas (billions of cubic feet) (62) (10) (25) (1) – – Commodity contracts – crude oil (millions of barrels) 3 (18) (18) (9) – –Commodity contracts – NGL (millions of barrels) (5) –––––Commodity contracts – power (MWH) 25 40 40 30 31 –Notes to the Consolidated Financial Statements 149
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income The following table presents the effect of cash flow hedges and net investment hedges on the Company’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes. Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Amount of unrealized gains/(loss) recognized in OCI Cash ?ow hedges Foreign exchange contracts 77 856 Interest rate contracts (275) (1,086) 814 Commodity contracts 9 50 (9) Other contracts (47) 13 (2) Net investment hedges Foreign exchange contracts (248) (113) (81) (484) (1,128) 778 Amount of gains/(loss) reclassi?ed from AOCI to earnings (effective portion) Foreign exchange contracts1 9 8 (8) Interest rate contracts2 128 101 107 Commodity contracts3 (46) 41 Other contracts4 28 (7) – 119 106 100 De-designation of qualifying hedges in connection with the Canadian Restructuring Plan (Note 1) Interest rate contracts2,5 338 ––338 –– Amount of gains/(loss) reclassi?ed from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts2 21 216 51 Commodity contracts3 5 (6) (3) 26 210 48 1 Reported within Transportation and other services revenues and Other expense in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 The amounts above include $338millionrelating to the de-designation of qualifying hedges in connection with the Canadian Restructuring Plan. The Company estimates that $71 million of AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which the Company is hedging exposures to the variability of cash flows is 48 months as at December 31, 2015. Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of the Company’s non-qualifying derivatives. Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Foreign exchange contracts1 (2,187) (936) (738) Interest rate contracts2 (363) 4(10) Commodity contracts3 199 1,031 (496) Other contracts4 (22) 7(3) Total unrealized derivative fair value gains/(loss) (2,373) 106 (1,247)1 Reported within Transportation and other services revenues (2015 – $1,383 million loss; 2014 – $496 million loss; 2013 – $352 million loss) and Other expense (2015 – $804 million loss; 2014 – $440 million loss; 2013 – $386 million loss) in the Consolidated Statements of Earnings.2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues (2015 – $328 million gain; 2014 – $741 million gain; 2013 – $375 million loss), Commodity sales (2015 – $226 million loss; 2014 – nil; 2013 – nil), Commodity costs (2015 – $99 million gain; 2014 – $303 million gain; 2013 – $35 million loss) and Operating and administrative expense (2015 – $2 million loss; 2014 – $13 million loss; 2013 – $86 million loss) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 150 Enbridge Inc. 2015 Annual Report
Liquidity Risk Liquidity risk is the risk 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, 2015. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities. Credit Risk Entering into derivative ?nancial instruments may result in exposure to credit risk. Credit risk arises from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, the Company enters into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements. The Company had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2015 2014 (millions of Canadian dollars) Canadian ?nancial institutions 47 58 United States ?nancial institutions 450 240 European ?nancial institutions 95 73 Asian ?nancial institutions 4 – Other1 213 310 809 681 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at December 31, 2015, the Company had provided letters of credit totalling $166 million in lieu of providing cash collateral to its counterparties pursuant to the terms of the relevant ISDA agreements. The Company held $17 million of cash collateral on derivative asset exposures at December 31, 2015 and $33 million of cash collateral at December 31, 2014. Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of the Company’s counterparties using their credit default swap spread rates, and are reflected at fair value. For derivative liabilities, the Company’s non-performance risk is considered in the valuation. 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 diversi?ed customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the ?nancial strength of large industrial customers and, in select cases, has obtained additional security to minimize the risk of default on receivables. Generally, the Company classi?es and provides for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative ?nancial assets is their carrying value.
Fair Value Measurements The Company’s financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. The Company also discloses the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects the Company’s best estimates of market value based on generally accepted valuation techniques or models and are supported by observable market prices and rates. When such values are not available, the Company uses discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. Fair Value of Financial Instruments The Company categorizes its derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The Company’s Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations. Level 2 Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained. The Company has also categorized the fair value of its held to maturity preferred share investment and long-term debt as Level 2. The fair value of the Company’s held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of the Company’s long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. Level 3 Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. The Company has developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power contracts and NGL and natural gas contracts, basis swaps, commodity swaps, power and energy swaps, as well as options. The Company does not have any other financial instruments categorized in Level 3. 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 classi?ed in Levels 2 and 3, the Company uses standard valuation techniques to calculate the estimated fair value. These methods include discounted cash ?ows 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 price) 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.
Fair Value of Derivatives The Company has categorized its derivative assets and liabilities measured at fair value as follows: Total Gross Derivative December 31, 2015 Level 1 Level 2 Level 3 Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts –10 –10 Interest rate contracts –2 –2 Commodity contracts 14 210 555 779 Other contracts –––– 14 222 555 791 Long-term derivative assets Foreign exchange contracts –128 –128 Interest rate contracts –18 –18 Commodity contracts –121 106 227 Other contracts –––– –267 106 373 Financial liabilities Current derivative liabilities Foreign exchange contracts – (872) – (872) Interest rate contracts –(564) –(564) Commodity contracts (3) (130) (368) (501) Other contracts –(8) –(8) (3) (1,574) (368) (1,945) Long-term derivative liabilities Foreign exchange contracts – (3,048) – (3,048) Interest rate contracts –(629) –(629) Commodity contracts – (21) (239) (260) Other contracts –(13) –(13) –(3,711) (239) (3,950) Total net ?nancial asset/(liability) Foreign exchange contracts –(3,782) –(3,782) Interest rate contracts –(1,173) –(1,173) Commodity contracts 11 180 54 245 Other contracts –(21) –(21) 11 (4,796) 54 (4,731)
Total Gross Derivative December 31, 2014 Level 1 Level 2 Level 3 Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts –13 –13 Interest rate contracts –8 –8 Commodity contracts 62 140 333 535 Other contracts –12 –12 62 173 333 568 Long-term derivative assets Foreign exchange contracts –51 –51 Interest rate contracts –5 –5 Commodity contracts – 22 113 135 Other contracts –8 –8 –86 113 199 Financial liabilities Current derivative liabilities Foreign exchange contracts –(301) –(301) Interest rate contracts –(438) –(438) Commodity contracts (28) (137) (116) (281) (28) (876) (116) (1,020) Long-term derivative liabilities Foreign exchange contracts – (1,196) – (1,196) Interest rate contracts –(576) –(576) Commodity contracts – (125) (181) (306) – (1,897) (181) (2,078) Total net ?nancial asset/(liability) Foreign exchange contracts –(1,433) –(1,433) Interest rate contracts –(1,001) –(1,001) Commodity contracts 34 (100) 149 83 Other contracts –20 –20 34 (2,514) 149 (2,331) The signi?cant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: Fair Unobservable Minimum Maximum Weighted Unit of December 31, 2015 Value Input Price Price Average Price Measurement (fair value in millions of Canadian dollars) Commodity contracts – financial1 Natural gas (2) Forward gas price 2.89 4.26 3.53 $/mmbtu3 NGL 8 Forward NGL price 0.21 1.28 0.87 $/gallon Power (148) Forward power price 30.00 73.76 53.44 $/MWH Commodity contracts – physical1 Natural gas (69) Forward gas price 2.04 5.69 3.14 $/mmbtu3 Crude 132 Forward crude price 28.59 87.40 51.71 $/barrel NGL 3 Forward NGL price 0.21 1.67 0.74 $/gallon Commodity options2 Crude 51 Option volatility 26% 37% 32% NGL 79 Option volatility 13% 74% 34% 54 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 Commodity options contracts are valued using an option model valuation technique. 3 One million British thermal units (mmbtu). Enbridge Inc. 2015 Annual Report
If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of the Company’s Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices and, for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for the Company’s Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally speaking, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility. Changes in net fair value of derivative assets and liabilities classi?ed as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2015 2014 (millions of Canadian dollars) Level 3 net derivative asset/(liability) at beginning of period 149 (164) Total gains/(loss) Included in earnings1 136 252 Included in OCI (1) 32 Settlements (230) 29 Level3net derivativeasset at end of period 54 149 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. The Company’s policy is to recognize transfers as of the last day of the reporting period. There were no transfers between levels as at December 31, 2015 or 2014. Fair Value Of Other Financial Instruments The Company recognizes equity investments in other entities not categorized as held to maturity at fair value, with changes in fair value recorded in OCI, unless actively quoted prices are not available for fair value measurement in which case these investments are recorded at cost. The carrying value of all equity investments recognized at cost totalled $126 million at December 31, 2015 (2014 – $99 million). The Company has a held to maturity preferred share investment carried at its amortized cost of $344 million as at December 31, 2015 (2014 – $323 million). These preferred shares are entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in greater than 10 years plus a range of 4.3% to 4.4%. As at December 31, 2015, the fair value of this preferred share investment approximates its face value of $580 million (2014 – $580 million). As at December 31, 2015, the Company’s long-term debt had a carrying value of $41,530 million (2014 – $34,427 million) and a fair value of $41,045 million (2014 – $36,637 million). Net Investment Hedges The Company has designated a portion of its United States dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of its net investment in United States dollar denominated investments and subsidiaries. During the year ended December 31, 2015, the Company recognized an unrealized foreign exchange loss on the translation of United States dollar denominated debt of $631 million (2014 – unrealized loss of $199 million) and an unrealized loss on the change in fair value of its outstanding foreign exchange forward contracts of $250 million (2014 – unrealized loss of $114 million) in OCI. The Company also recognized a realized gain of $4 million (2014 – realized gain of $10 million) in OCI associated with the settlement of foreign exchange forward contracts and a realized loss of $75 million (2014 – nil) in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the year ended December 31, 2015 (2014 – nil). Notes to the Consolidated Financial Statements
25. Income Taxes Income Tax Rate Reconciliation Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Earnings before income taxes and discontinued operations 11 2,173 613 Canadian federal statutory income tax rate 15% 15% 15% Expected federal taxes at statutory rate 2 326 92 Increase/(decrease) resulting from: Provincialandstateincometaxes1 (204) (36) (1) Foreign and other statutory rate differentials 310 394 45 Effects of rate-regulated accounting2 (52) (97) (55) Foreign allowable interest deductions (84) (65) (39) Part VI.1 tax, net of federal Part I deduction3 55 47 23 Intercompany sale of investment4 23 68 – Valuation allowance5 154 21 Noncontrolling interests (28) (28) 26 Other6 (6) –31 Income taxes on earnings before discontinued operations 170 611 123 Effective income tax rate 1,545.5% 28.1% 20.1% 1 The higher provincial and state income tax recovery in 2015 reflected the decrease in earnings largely in the Company’s Canadian operations due to the depreciation in the Canadian dollar value against the U.S. dollar. 2 The amount in 2015 included the federal component of the tax effect of the write-off of regulatory receivables. 3 The amount in 2013 was presented net of an $11 million federal tax recovery related to changes to tax law enacted during the year. 4 In September 2015 and November 2014, Enbridge sold certain assets to entities under common control. The intercompany gains realized on these transfers were eliminated. However, because these transactions involved the sale of partnership units, tax consequences have been recognized in earnings. This resulted in a tax expense of $39 million and $157million in 2015 and 2014, respectively. 5 The amount in 2015 represents the federal component of the tax effect of a valuation allowance on the deferred tax assets related to an outside basis temporary difference that is no longer more likely than not to be realized. 6 2015 and 2013 included $17million recovery and $55million expense, respectively, related to the federal component of the tax effect of adjustments related to prior periods. Components of Pretax Earnings and Income Taxes Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Earnings before income taxes and discontinued operations Canada (1,365) 114 193 United States 808 1,614 132 Other 568 445 288 11 2,173 613 Current income taxes Canada 157 35 (30) United States 3 (15) 18 Other 3 44 163 24 (8) Deferred income taxes Canada (558) (193) 31 United States 565 780 100 7 587 131 Income taxes on earnings before discontinued operations 170 611 123
Components of Deferred Income Taxes Deferred tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are as follows: December 31, 2015 2014 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (3,423) (2,668) Investments (3,024) (2,469) Regulatory assets (354) (240) Other (85) (102) Total deferred income tax liabilities (6,886) (5,479) Deferred income tax assets Financial instruments 1,374 644 Pension and OPEB plans 202 203 Loss carry forwards 848 390 Other 274 246 Total deferred ncome tax assets 2,698 1,483 Less valuation allowance (538) (42) Total deferred income tax assets, net 2,160 1,441 Net deferred income tax liabilities (4,726) (4,038) Presented as follows: Accounts receivable and other (Note 7) 367 245 Deferred income taxes 839 561 Total deferred income tax assets 1,206 806 Accounts payable and other (17) (2) Deferred income taxes (5,915) (4,842) Total deferred income tax liabilities (5,932) (4,844) Net deferred income tax liabilities (4,726) (4,038) Valuation allowances have been established for certain loss and credit carryforwards, and outside basis temporary differences on investments that reduce deferred income tax assets to an amount that will more likely than not be realized. As at December 31, 2015, the Company recognized the bene?t of unused tax loss carryforwards of $1,754 million (2014 – $826 million) in Canada which start to expire in 2025 and beyond. As at December 31, 2015, the Company recognized the bene?t of unused tax loss carryforwards of $899 million (2014 – $394 million) in the United States which start to expire in 2030 and beyond. The Company has not provided for deferred income taxes on the difference between the carrying value of substantially all of its foreign subsidiaries and their corresponding tax basis as the earnings of those subsidiaries are intended to be permanently reinvested in their operations. As such these investments are not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying values of the investments and their tax bases is largely a result of unremitted earnings and currency translation adjustments. The unremitted earnings and currency translation adjustment for which no deferred taxes have been recognized in respect of foreign subsidiaries is $4.0 billion (2014 – $4.7 billion). If such earnings are remitted, in the form of dividends or otherwise, the Company may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is not practicable. The Company and one or more of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which the Company is subject to potential examinations include the United States (Federal and Texas) and Canada (Federal, Alberta and Ontario). The Company’s 2008 to 2015 taxation years are still open for audit in the Canadian and United States jurisdictions. The Company is currently under examination for income tax matters in Canada for the 2011 and 2012 taxation years, and in the United States for the 2009 to 2013 taxation years. The Company is not currently under examination for income tax matters in any other jurisdiction where it is subject to income tax. Notes to the Consolidated Financial Statements
Unrecognized Tax Bene?ts Year ended December 31, 2015 2014 (millions of Canadian dollars) Unrecognized tax bene?ts at beginning of year 51 46 Gross increases for tax positions of current year 5 5 Reduction for lapse of statute of limitations –(5) Change in translation of foreign currency 9 5 Unrecognized tax bene?ts at end of year 65 51 The unrecognized tax benefits as at December 31, 2015, if recognized, would affect the Company’s effective income tax rate. The Company does not anticipate further adjustments to the unrecognized tax bene?ts during the next 12 months that would have a material impact on its consolidated ?nancial statements. The Company recognizes accrued interest and penalties related to unrecognized tax bene?ts as a component of Income taxes. Income tax expense for the year ended December 31, 2015 included $2 million expense (2014 – nil; 2013 – $5 million recovery) of interest and penalties. As at December 31, 2015, interest and penalties of $7 million (2014 – $5 million) have been accrued. 26. Retirement and Postretirement Bene?ts Pension Plans The Company has three registered pension plans which provide either de?ned bene?t or de?ned contribution pension bene?ts, or both, to employees of the Company. The Canadian Plans provide Company funded de?ned bene?t pension and/or de?ned contribution bene?ts to Canadian employees of Enbridge. The United States Plan provides Company funded de?ned bene?t pension bene?ts for United States based employees. The Company has four supplemental pension plans that provide pension bene?ts in excess of the basic plans for certain employees. A measurement date of December 31, 2015 was used to determine the plan assets and accrued bene?t obligation for the Canadian and United States plans. De?ned Bene?t Plans Benefits payable from the defined benefit plans are based on members’ years of service and final average remuneration. These benefits are partially inflation indexed after a member’s retirement. In 2014, the mortality assumption was revised for the United States Plan resulting in an increase to pension liabilities of $21 million. Contributions by the Company are made in accordance with independent actuarial valuations and are invested primarily in publicly-traded equity and ?xed income securities. The effective dates of the most recent actuarial valuations and the next required actuarial valuations for the basic plans are as follows: Effective Date of Most Recently Effective Date of Next Filed Actuarial Valuation Required Actuarial Valuation Canadian Plans Liquids Pipelines December 31, 2014 December 31, 2015 Gas Distribution December 31, 2013 December 31, 2016 United States Plan January 1, 2015 January 1, 2016 De?ned Contribution Plans Contributions are generally based on the employee’s age, years of service and remuneration. For defined contribution plans, bene?t costs equal amounts required to be contributed by the Company. Enbridge Inc. 2015 Annual Report
Other Postretirement Benefits OPEB primarily includes supplemental health and dental, health spending accounts and life insurance coverage for qualifying retired employees. Benefit Obligations and Funded Status The following tables detail the changes in the benefit obligation, the fair value of plan assets and the recorded asset or liability for the Company’s defined benefit pension plans and OPEB plans using the accrual method. Pension OPEB December 31, 2015 2014 2015 2014 (millions of Canadian dollars) Change in accrued benefit obligation Benefit obligation at beginning of year 2,470 1,903 276 240 Service cost 167 108 8 8 Interest cost 98 93 11 12 Employees’ contributions ––1 1 Actuarial (gains)/loss (172) 411 9 16 Benefitts paid (90) (75) (12) (9) Effect of foreign exchange rate changes 79 31 21 8 Other (1) (1) (6) – Benefit obligation at end of year 2,551 2,470 308 276 Change in plan assets Fair value of plan assets at beginning of year 2,062 1,799 99 81 Actual return on plan assets 88 179 (2) 7 Employer’s contributions 116 138 10 11 Employees’ contributions ––1 1 Benefits paid (90) (75) (12) (9) Effect of foreign exchange rate changes 54 22 19 8 Other (1) (1) –– Fair value of planassetsatendofyear1 2,229 2,062 115 99 Underfunded status at end of year (322) (408) (193) (177) Presented as follows: Deferred amounts and other assets 6 5 2 – Accounts payable and other ––(6) (6) Other long-term liabilities (Note 18) (328) (413) (189) (171) (322) (408) (193) (177) 1 Assetsof$40million (2014–$32 million)are held by the Company in trust accounts that backnon-registered supplemental pension plans benefitting United States plan participants. DuetoUnited Statestax regulations, the seassetsarenot restricted fromcreditors, and therefore theCompanyisunabletoincludethesebalancesin plan assets for accounting purposes. However, these assets are committed for the future settlement of non-registered supplemental pension plan obligations included in the underfunded statusas at the end o fthey ear. The weighted average assumptions made in the measurement of the projected benefit obligations of the pension plans and OPEB are as follows: Pension OPEB Year ended December 31, 2015 2014 2013 2015 2014 2013 Discount rate 4.2% 4.0% 5.0% 4.2% 3.9% 4.9% Averagerateofsalaryincreases 3.6% 4.0% 3.7% Notes to the Consolidated Financial Statements
Net Benefit Costs Recognized Pension OPEB Year ended December 31, 2015 2014 2013 2015 2014 2013 (millions of Canadian dollars) Benefits earned during the year 167 108 103 8 89 Interest cost on projected benefit obligations 98 93 79 11 12 11 Expected returnonplanassets (142) (123) (103) (6) (5) (4) Amortization of prior service costs ––1 ––– Amortization of actuarial loss 49 28 52 1 –2 Netdefined benefitcostson an accrual basis 172 106 132 14 15 18 Defined contribution benefit costs 4 44 ––– Netbenefitcostrecognized in Earnings 176 110 136 14 15 18 Amount recognized in OCI: Net actuarial (gains)/loss1 (107) 232 (158) 16 15 (45) Net prior service cost/(credit)2 –––(6) –2 Totalamount recognizedinOCI (107) 232 (158) 10 15 (43) Total amount recognized in Comprehensive income 69 342 (22) 24 30 (25) 1 Unamortized actuarial losses included in AOCI, before tax, were $404 million (2014 – $489 million) relating to the pension plans and $44 million (2014 – $26 million) relating to OPEB at December 31, 2015. 2 Unamortized prior service credits included in AOCI, before tax, were $1 million (2014 – $6 million costs) relating to OPEB at December 31, 2015. The Company estimates that approximately $35 million related to pension plans and $1 million related to OPEB at December 31, 2015 will be reclassified from AOCI into earnings in the next 12 months. Regulatory adjustments are recorded in the Consolidated Statements of Earnings, the Consolidated Statements of Comprehensive Income and the Consolidated Statements of Financial Position to refiect the difference between pension expense for accounting purposes and pension expense for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent pension or OPEB costs or gains are expected to be collected from or refunded to customers in future rates (Note 5). For the year ended December 31, 2015, an offsetting regulatory asset of nil (2014 – $3 million regulatory liability) has been recorded to the extent pension and OPEB costs are expected to be collected from customers in future rates. The weighted average assumptions made in the measurement of the cost of the pension plans and OPEB are as follows: Pension OPEB Year ended December 31, 2015 2014 2013 2015 2014 2013 Discount rate 4.0% 5.0% 4.2% 3.9% 4.9% 4.0% Averagerateof returnonplanassets 6.7% 6.7% 6.7% 6.0% 6.0% 6.0% Averagerateofsalaryincreases 4.0% 3.7% 3.7% Enbridge Inc. 2015 Annual Report
Medical Cost Trends The assumed rates for the next year used to measure the expected cost of bene?ts are as follows: Medical Cost Trend Ultimate YearinwhichUltimate Rate Assumption for Medical Cost Trend MedicalCostTrendRate NextFiscalYear Rate Assumption Assumption is Achieved Canadian Plans Drugs 6.7% 4.4% 2034 Other medical 4.5% – – United States Plan 7.0% 4.5% 2037 A 1% increase in the assumed medical care trend rate would result in an increase of $37 million in the benefit obligation and an increase of $2 million in benefit and interest costs. A 1% decrease in the assumed medical care trend rate would result in a decrease of $31 million in the benefit obligation and a decrease of $2 million in benefit and interest costs. Plan Assets The Company manages the investment risk of its pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash ?ow requirements of the plan; (iv) the operating environment and ?nancial situation of the Company and its ability to withstand ?uctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets. The overall expected rate of return is based on the asset allocation targets with estimates for returns on equity and debt securities based on long-term expectations. Expected Rate of Return on Plan Assets Pension OPEB Year ended December 31, 2015 2014 2015 2014 Canadian Plans 6.7% 6.7% United States Plan 7.2% 7.2% 6.0% 6.0% Target Mix for Plan Assets Canadian Plans Liquids Pipelines Plan Gas Distribution Plan United States Plan Equity securities 62.5% 53.5% 62.5% Fixed income securities 30.0% 40.0% 30.0% Other 7.5% 6.5% 7.5% Notes to the Consolidated Financial Statements
Major Categories of Plan Assets Plan assets are invested primarily in readily marketable investments with constraints on the credit quality of fixed income securities. As at December 31, 2015, the pension assets were invested 56.4% (2014 – 57.0%) in equity securities, 31.4% (2014 – 32.2%) in fixed income securities and 12.2% (2014 – 10.8%) in other. The OPEB assets were invested 59.1% (2014 – 58.8%) in equity securities, 40.0% (2014 – 40.2%) in fixed income securities and 0.9% (2014 – 1.0%) in other. The following table summarizes the Company’s pension financial instruments at fair value. Non-financial instruments with a carrying value of $21 million asset (2014 – $4 million asset) and refundable tax assets of $106 million (2014 – $96 million) have been excluded from the table below. 2015 2014 December 31, Level 11 Level 22 Level 33 Total Level 11 Level 22 Level 33 Total (millions of Canadian dollars) Pension Cash and cash equivalents 37 – – 37 42 – – 42 Fixed income securities Canadian government bonds 131 – – 131 121 – – 121 Corporate bonds and debentures 53 –8 44 –8 Canadian corporate bond index fund 259 – – 259 254 – – 254 Canadian government bond index fund 201 – – 201 198 – – 198 UnitedStatesdebtindexfund 102 – – 102 84 – – 84 Equity Canadian equity securities 133 – – 133 131 – – 131 United States equity securities 2–– 2 31 – – 31 Global equity securities 106 25 – 131 11 – – 11 Canadian equity funds 253 – – 253 255 – – 255 United States equity funds 243 5 – 248 185 36 – 221 Global equity funds 161 148 – 309 342 134 – 476 Infrastructure4 – – 182 182 – – 51 51 Real estate4 – – 115 115 –– 81 81 Forward currency contracts –(10) –(10) – (1) – (1) OPEB Cash and cash equivalents 2–– 2 1–– 1 Fixed income securities United States government and government agency bonds 46 – – 46 39 – – 39 Equity United States equity funds 34 – – 34 30 – – 30 Global equity funds 34 – – 34 27 – – 27 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2assetsincludeassetswith signi?cant observableinputs. 3 Level 3 assets include assets with signi?cant unobservable inputs. 4 Thefairvalues oftheinfrastructureand real estate investments are established through the use of valuation models. Changes in the net fair value of plan assets classi?ed as Level 3 in the fair value hierarchy were as follows: December 31, 2015 2014 (millions of Canadian dollars) Balance at beginning of year 132 126 Unrealized and realized gains 44 26 Purchases and settlements, net 121 (20) Balance at end of year 297 132 Enbridge Inc. 2015 Annual Report
Plan Contributions by the Company Pension OPEB Year ended December 31, 2015 2014 2015 2014 (millions of Canadian dollars) Total contributions 116 138 10 11 Contributions expected to be paid in 2016 118 11 Benefits Expected to be Paid by the Company Year ended December 31, 2016 2017 2018 2019 2020 2021– 2025 (millions of Canadian dollars) Expected future benefit payments 104 110 117 124 132 782 27. Other Income/(Expense) Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Net foreign currency loss (884) (400) (272) Allowance for equity funds used during construction 2 31 Interest income on affiliate loans 20 20 23 Interest income 4 34 Noverco preferred shares dividend income 40 42 40 Gains on dispositions (Note 6) 94 38 18 Other 22 28 51 (702) (266) (135) 28. Severance Costs Included in Operating and administrative and Other expense is $42 million and $4 million, respectively, in severance costs related to one-time termination benefits to employees, of which $20 million and $26 million are within the Sponsored Investments and Corporate segments, respectively. This resulted from an enterprise-wide reduction of workforce that occurred in November 2015 and affected approximately 5% of the Company’s workforce. In 2015, $22 million was paid with the remaining $24 million to be paid in 2016 and is included in Accounts payable and other as at December 31, 2015. 29. Changes in Operating Assets and Liabilities Year ended December 31, 2015 2014 2013 (millions of Canadian dollars) Accounts receivable and other 684 (91) (789) Accounts receivable from affiliates 82 (176) (53) Inventory (315) (186) (315) Deferred amounts and other assets 364 (431) (25) Accounts payable and other (1,454) (829) 832 Accounts payable to affiliates (26) 34 46 Interest payable 31 24 25 Other long-term liabilities (52) (66) (130) (686) (1,721) (409) Notes to the Consolidated Financial Statements
30. Related Party Transactions Related party transactions are conducted in the normal course of business and unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Vector, a joint venture, contracts the services of Enbridge to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, were $7 million for the year ended December 31, 2015 (2014 – $7 million; 2013 – $6 million). Certain wholly-owned subsidiaries within Gas Distribution, Gas Pipelines, Processing and Energy Services and Sponsored Investments segments have committed and uncommitted transportation arrangements with several joint venture affiliates that are accounted for using the equity method. Total amounts charged to the Company for transportation services for the year ended December 31, 2015 were $332 million (2014 – $256 million; 2013 – $222 million). A wholly-owned subsidiary within Liquids Pipelines had a lease arrangement with a joint venture affiliate. During the year ended December 31, 2015, expenses related to the lease arrangement totalled $151 million (2014 – $21 million; 2013 – nil) and were recorded to Operating and administrative expense. Certain wholly-owned subsidiaries within Gas Distribution and Gas Pipelines, Processing and Energy Services segments made natural gas and NGL purchases of $228 million (2014 – $315 million; 2013 – $99 million) from several joint venture affiliates during the year ended December 31, 2015. Natural gas sales of $5 million (2014 – $58 million; 2013 – $10 million) were made by certain wholly-owned subsidiaries within Gas Pipelines, Processing and Energy Services segment to several joint venture affiliates during the year ended December 31, 2015. Long-Term Notes Receivable from Affiliates Amounts receivable from affiliates include a series of loans to Vector and other affiliates totalling $149–million and $3 million, respectively (2014 – $183 million and nil, respectively), which require quarterly interest payments at annual interest rates ranging from 4% to 12%. These amounts are included in Deferred amounts and other assets. 31. Commitments and Contingencies Commitments At December 31, 2015, Enbridge had commitments as detailed below: Less than Total 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Purchase of services, pipe and other materials, including transportation 14,025 5,459 1,918 1,205 1,118 1,025 3,300 Capital and operating leases 739 110 103 60 56 51 359 Maintenance agreements 420 46 46 31 25 19 253 Land lease commitments 363 13 13 13 13 13 298 Total 15,547 5,628 2,080 1,309 1,212 1,108 4,210 Enbridge Energy Partners, L.P. As at December 31, 2015, Enbridge holds an approximate 35.7% (2014 – 33.7%; 2013 – 20.6%) combined direct and indirect economic interest in EEP, which is consolidated with noncontrolling interests within the Sponsored Investments segment. Lakehead System Lines 6A and 6B Crude Oil Releases Line 6B Crude Oil Release On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Kalamazoo River via Talmadge Creek, a waterway that feeds 164 Enbridge Inc. 2015 Annual Report
the Kalamazoo River. The released crude oil affected approximately 61 kilometres (38 miles) of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. EEP continues to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives EEP is undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. On March 14, 2013, EEP received an order from the United States Environmental Protection Agency (EPA) (the EPA Order) which required additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. In February 2015, the EPA acknowledged EEP’s completion of the EPA Order. In November 2014, regulatory authority was transferred from the EPA to the Michigan Department of Environmental Quality (MDEQ). The MDEQ has oversight over the submerged oil reassessment, sheen management and sediment trap monitoring and maintenance activities through a Kalamazoo River Residual Oil Monitoring and Maintenance Work Plan. In May 2015, EEP reached a settlement with the MDEQ and the Michigan Attorney General’s offices regarding the Line 6B crude oil release. As stipulated in the settlement, EEP agrees to: (1) provide at least 300 acres of wetland through restoration, creation, or banked wetland credits, to remain as wetland in perpetuity; (2) pay US$5 million as mitigation for impacts to the banks, bottomlands, and flow of Talmadge Creek and the Kalamazoo River for the purpose of enhancing the Kalamazoo River watershed and restoring stream flows in the River; (3) continue to reimburse the State of Michigan for costs arising from oversight of EEP activities since the release; and (4) continue monitoring, restoration and invasive species control within state-regulated wetlands affected by the release and associated response activities. The timing of these activities is based upon the work plans approved by the State of Michigan. As at December 31, 2015, EEP’s total cost estimate for the Line 6B crude oil release was US$1.2 billion ($193 million after-tax attributable to Enbridge), which is unchanged since December 31, 2014. As at December 31, 2014, the total cost estimate for the Line 6B crude oil release increased by US$86 million as compared to December 31, 2013. The total cost increase of US$86 million during the year ended December 31, 2014, was primarily related to the MDEQ approved Schedule of Work, completion of the dredge activities near Ceresco and Morrow Lake and estimated civil penalties under the Clean Water Act of the United States (Clean Water Act), as described below under Legal and Regulatory Proceedings. Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at December 31, 2015. Despite the efforts EEP has made to ensure the reasonableness of its estimates, there continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies, in addition to fines and penalties and expenditures associated with litigation and settlement of claims. Line 6A Crude Oil Release A release of crude oil from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. EEP estimates that approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Some of the released crude oil went onto a roadway, into a storm sewer, a waste water treatment facility and then into a nearby retention pond. All but a small amount of the crude oil was recovered. EEP completed excavation and replacement of the pipeline segment and returned it to service on September 17, 2010. EEP has completed the cleanup, remediation and restoration of the areas affected by the release. On October 21, 2013, the National Transportation Safety Board publicly posted their final report related to the Line 6A crude oil release which states the probable cause of the crude oil release was erosion caused by a leaking water pipe resulting from an improperly installed third-party water service line below EEP’s oil pipeline. The total estimated cost for the Line 6A crude oil release was approximately US$51 million ($7 million after-tax attributable to Enbridge) before insurance recoveries and excluding fines and penalties. These costs included emergency response, environmental remediation and cleanup activities with the crude oil release. As at December 31, 2015, EEP has no remaining estimated liability. Insurance EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates which renews throughout the year. On May 1 of each year, the insurance program is renewed and includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents excluding costs for fines and penalties. A majority of the costs incurred in connection with the crude oil release for Line 6B are covered by Enbridge‘s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability for Enbridge and its affiliates. Including EEP‘s remediation spending through December 31, 2015, costs related to Line 6B exceeded the limits of the coverage available under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy. As at December 31, 2015, EEP has recorded total insurance recoveries of US$547 million ($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million aggregate limit. EEP will record receivables for additional amounts it claims for recovery pursuant to its insurance policies during the period it deems recovery to be probable. In March 2013, EEP and Enbridge filed a lawsuit against the insurer who is disputing recovery eligibility for Line 6B costs. In March 2015, Enbridge reached an agreement with that insurer to submit the claim to binding arbitration which is not scheduled to occur until the fourth quarter of 2016. While the Company believes that those costs are eligible for recovery, there can be no assurance that it will prevail in the arbitration. Notes to the Consolidated Financial Statements 165
Enbridge renewed its comprehensive property and liability insurance programs under which the Company is insured through April 30, 2016 with a liability program aggregate limit of US$860 million, which includes sudden and accidental pollution liability. In the unlikely event multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among Enbridge entities on an equitable basis based on an insurance allocation agreement among Enbridge and its subsidiaries. Legal and Regulatory Proceedings A number of United States governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Five actions or claims are pending against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release. Based on the current status of these cases, the Company does not expect the outcome of these actions to be material to its results of operations or financial condition. As at December 31, 2015, included in EEP‘s estimated costs related to the Line 6B crude oil release is US$44 million in fines and penalties. Of this amount, US$40 million relates to civil penalties under the Clean Water Act. While no final fine or penalty has been assessed or agreed to date, EEP believes that, based on the best information available at this time, the US$40 million represents an estimate of the minimum amount which may be assessed, excluding costs of injunctive relief that may be agreed to with the relevant governmental agencies. Given the complexity of settlement negotiations, which EEP expects will continue, and the limited information available to assess the matter, EEP is unable to reasonably estimate the final penalty which might be incurred or to reasonably estimate a range of outcomes at this time. Injunctive relief is likely to include further measures directed toward enhancing spill prevention, leak detection and emergency response to environmental events. The cost of compliance with such measures, when combined with any fine or penalty, could be material. EEP has entered into a tolling agreement with the applicable governmental agencies and discussions with these governmental agencies regarding fines, penalties and injunctive relief are ongoing. In June 2015, Enbridge reached a separate agreement with the United States (Federal Natural Resources Damages Trustees), State of Michigan (State Natural Resources Damages Trustees), Match-E-Be-Nash-She-Wish Band of the Potawatomi Indians and the Nottawaseppi Huron Band of the Potawatomi Indians, and paid approximately US$4 million that was accrued to cover a variety of projects, including the restoration of 175 acres of oak savanna in Fort Custer State Recreation Area and wild rice beds along the Kalamazoo River. One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court in connection with this crude oil release. On February 20, 2015, EEP agreed to a consent order releasing it from any claims, liability, or penalties. Lakehead System Line 14 Crude Oil Release On July 27, 2012, a release of crude oil was detected on Line 14 of EEP‘s Lakehead System near Grand Marsh, Wisconsin. The estimated volume of oil released was approximately 1,700 barrels. EEP received a Corrective Action Order (CAO) from the 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 again considered the status of the pipeline in light of information they acquired throughout 2014. On December 9, 2014, EEP received a letter from the PHMSA approving its request to continue the normal operation of Line 14 without pressure restrictions. EEP has no remaining estimated liability for this release. Aux Sable Notice of Violation In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the EPA for alleged violations of the Clean Air Act related to the Leak Detection and Repair program, and related provisions of the Clean Air Act permit for Aux Sable‘s Channahon, Illinois facility. As part of the ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believes to be an exceedance of currently permitted limits for Volatile Organic Material. Aux Sable received a second NFOV from the EPA in April 2015 in connection with this potential exceedance. Aux Sable is engaged in discussions with the EPA to evaluate the potential impact and ultimate resolution of these issues. At this time, the Company is unable to reasonably estimate the financial impact. Tax Matters Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company‘s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review. Other Litigation The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, Management believes that the resolution of such actions and proceedings will not have a material impact on the Company‘s consolidated financial position or results of operations. 166 Enbridge Inc. 2015 Annual Report
32. Guarantees The Company has agreed to indemnify EEP from and against substantially all liabilities, including liabilities relating to environmental matters, arising from operations prior to the transfer of its pipeline operations to EEP in 1991. This indemnification does not apply to amounts that EEP would be able to recover in its tariff rates if not recovered through insurance or to any liabilities relating to a change in laws after December 27, 1991. The Company has also agreed to indemnify EEM for any tax liability related to EEM‘s formation, management of EEP and ownership of i-units of EEP. The Company has not made any significant payment under these tax indemnifications. The Company does not believe there is a material exposure at this time. The Company has also agreed to indemnify the Fund Group for certain liabilities relating to environmental matters arising from operations prior to the transfer of certain assets and interests to the Fund Group in 2012 and prior to the transfer of certain assets and interests to the Fund Group as part of the Canadian Restructuring Plan. The Company has also agreed to pay defined payments to the Fund Group on their investment in Southern Lights in the event shippers do not elect to extend their current contracts post June 2025. Following the completion of the Canadian Restructuring Plan, EIPLP indirectly owns all of the Class B Units of Southern Lights Canada, together with the Class A Units it already owned. As a result EIPLP holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights Canada. The Enbridge guarantee provided in respect of distributions on the Class A Units of Southern Lights Canada was released upon closing of the Canadian Restructuring Plan. In the normal course of conducting business, the Company enters into agreements which indemnify third parties and affiliates. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations, warranties or covenants, loss or damages to property, environmental liabilities, changes in laws, valuation differences, litigation and contingent liabilities. The Company may indemnify the purchaser for certain tax liabilities incurred while the Company owned the assets or for a misrepresentation related to taxes that result in a loss to the purchaser. Similarly, the Company may indemnify the purchaser of assets for certain tax liabilities related to those assets. The Company cannot reasonably estimate the maximum potential amounts that could become payable to third parties and affiliates under these agreements; however, historically, the Company has not made any significant payments under indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. The indemnifications and guarantees have not had, and are not reasonably likely to have, a material effect on the Company‘s financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources. 33. Subsequent Event On January 7, 2016, the Company signed an asset purchase and sale agreement to acquire 100% interest in the Tupper Main and Tupper West gas plants and associated pipelines for approximately $538 million. The purchase price will initially be funded from available sources of liquidity. The acquired assets are located near Dawson Creek, British Columbia with an aggregate processing capacity of 320 million cubic feet per day of raw gas from the Dawson Creek area Montney field. The purchase is expected to close in the second quarter of 2016. Notes to the Consolidated Financial Statements 167
Glossary ACFFO available cash flow from operations EGNB Enbridge Gas New Brunswick Inc. AFUDC allowance for funds used during construction EIPLP Enbridge Income Partners LP ALJ Administrative Law Judge Enbridge Enbridge Inc. AOCI accumulated other comprehensive income/(loss) ENF Enbridge Income Fund Holdings Inc. ARO asset retirement obligations EPA Environmental Protection Agency ASU Accounting Standards Update EPAI Enbridge Pipelines (Athabasca) Inc. bcf/d billion cubic feet per day EPI Enbridge Pipelines Inc. bpd barrels per day EUB New Brunswick Energy and Utilities Board CLT Canadian Local Toll FERC Federal Energy Regulatory Commission CSR corporate social responsibility GP general partner CTS Competitive Toll Settlement GTA Greater Toronto Area ECT Enbridge Commercial Trust HLBV hypothetical liquidation book value EECI Enbridge Energy Company, Inc. IDR incentive distribution rights EELP Enbridge Energy, Limited Partnership IDU incentive distribution units EEM Enbridge Energy Management, L.L.C. IJT International Joint Tariff EEP Enbridge Energy Partners, L.P. IR Plan incentive rate plan EGD Enbridge Gas Distribution Inc. ISO incentive stock options 168 Enbridge Inc. 2015 Annual Report
JRP Joint Review Panel PHMSA Pipeline and Hazardous Materials Safety Administration L3R Line 3 replacement PPA power purchase agreement LMCI land matters consultation initiative PSO performance stock options LNG liquefied natural gas PSU performance stock units MD&A Management‘s Discussion and Analysis ROE return on equity MEP Midcoast Energy Partners, L.P. RSU restricted stock units mmcf/d million cubic feet per day the Company Enbridge Inc. MW megawatts the Fund Enbridge Income Fund MWH megawatt hours TPDR temporary performance distribution rights NEB National Energy Board U.S. GAAP accounting principles generally accepted NGL natural gas liquids in the United States of America OCI other comprehensive income/(loss) VIE variable interest entity OEB Ontario Energy Board WCSB Western Canadian Sedimentary Basin Offshore Enbridge Offshore Pipelines WRGGS Walker Ridge Gas Gathering System OPEB other postretirement benefit obligations OPEC Organization of Petroleum Exporting Countries ORM operational risk management Glossary 169
Five-Year Consolidated Highlights 2015 2014 2013 2012 2011 (millions of Canadian dollars; per share amounts in Canadian dollars) Earnings attributable to common shareholders 1 Liquids Pipelines (224) 463 427 697 470 Gas Distribution 222 213 129 207 (88) 1 Gas Pipelines, Processing and Energy Services 218 617 (64) (456) 322 1 Sponsored Investments 479 419 268 283 268 Corporate (732) (558) (314) (129) (171) (37) 1,154 446 602 801 2 Earnings per common share (0.04) 1.39 0.55 0.78 1.07 2 Diluted earnings per common share (0.04) 1.37 0.55 0.77 1.05 3 Adjusted earnings 4 Liquids Pipelines 691 858 770 655 501 Gas Distribution 210 177 176 176 173 4 Gas Pipelines, Processing and Energy Services 89 136 203 176 180 4 Sponsored Investments 859 429 313 264 243 Corporate 17 (26) (28) (30) (16) 1,866 1,574 1,434 1,241 1,081 2,3 Adjusted earnings per common share 2.20 1.90 1.78 1.61 1.44 Cash flow data Cash provided by operating activities 4,571 2,547 3,341 2,874 3,371 Cash used in investing activities (7,933) (11,891) (9,431) (6,204) (5,079) Cash provided by financing activities 2,973 9,770 5,070 4,395 2,030 5 Available cash flow from operations 6 Available cash flow from operations 3,154 2,506 2,527 6 Available cash flow from operations per common share 3.72 3.02 Dividends Common share dividends declared 1,596 1,177 1,035 895 759 2 Dividends paid per common share 1.86 1.40 1.26 1.13 0.98 Shares outstanding (millions) 2 Weighted average common shares outstanding 847 829 806 772 751 2 Diluted weighted average common shares outstanding 858 840 817 785 761 1 Effective September 1, 2015, Enbridge transferred its Canadian Liquids Pipelines business and certain Canadian renewable energy assets to the Fund Group within the Sponsored Investments segment under the Canadian Restructuring Plan. Losses from the Canadian Liquids Pipelines assets prior to the date of transfer of $403 million in the year ended December 31, 2015 (2014 earnings of $320 million; 2013 earnings of $261 million) and earnings from the Canadian renewable energy assets within the Gas Pipelines, Processing and Energy Services segment prior to the date of transfer of $1 million in the year ended December 31, 2015 (2014 loss of $2 million; 2013 loss of $55 million), have not been reclassified into the Sponsored Investments segment for presentation purposes. 2 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011. 3 Adjusted earnings represent earnings attributable to common shareholders adjusted for non-recurring or non-operating factors. Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures, see page 27. 4 Adjusted earnings from the Canadian Liquids Pipelines assets prior to the date of transfer of $508 million in the year ended December 31, 2015 (2014 $688 million; 2013 $631 million) and adjusted earnings from the Canadian renewable energy assets within the Gas Pipelines, Processing and Energy Services segment prior to the date of transfer under the Canadian Restructuring Plan of $6 million in the year ended December 31, 2015 (2014 loss of $3 million; 2013 loss of $4 million), have not been reclassified into the Sponsored Investments segment for presentation purposes. 5 ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in regulatory assets and liabilities and environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. ACFFO is a non-GAAP measure that does not have any standardized meaning prescribed by GAAP see Non-GAAP Measures. 6 ACFFO was introduced in 2015 with two years of comparative information and one year of comparative information for ACFFO per common share. 170 Enbridge Inc. 2015 Annual Report
Five-Year Consolidated Highlights 2015 2014 2013 2012 2011 (millions of Canadian dollars; per share amounts in Canadian dollars) 1 Common share trading (TSX) High 66.14 65.13 49.17 43.05 38.17 Low 40.17 45.45 41.74 35.39 27.05 Close 46.00 59.74 46.41 43.02 38.09 Volume (millions) 416 320 342 365 396 Financial ratios 2 Return on average equity (0.2%) 7.3% 3.5% 6.4% 11.5% 3 Return on average capital employed 2.3% 3.9% 3.2% 3.5% 4.5% 4 Debt to debt plus total equity 65.5% 63.1% 58.2% 60.2% 64.8% 5 Dividend payout ratio 84.5% 73.7% 70.8% 70.2% 68.1% Operating data Liquids Pipelines Average deliveries (thousands of barrels per day) 6 Canadian Mainline 2,185 1,995 1,737 1,646 1,554 7 Regional Oil Sands System 759 703 533 414 334 Lakehead System 2,315 2,113 1,816 1,790 1,700 Gas Pipelines Average throughput volume (millions of cubic feet per day) Alliance Pipeline Canada 1,488 1,556 1,565 1,534 1,564 Alliance Pipeline US 1,645 1,682 1,565 1,553 1,564 Gas Distribution Enbridge Gas Distribution Inc. (EGD) Volumes (billions of cubic feet) 437 461 434 395 426 8 Number of active customers (thousands) 2,129 2,098 2,065 2,032 1,997 9 Heating degree days Actual 3,710 4,044 3,746 3,194 3,597 Forecast based on normal weather 3,536 3,517 3,668 3,532 3,602 1 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011. 2 Earnings applicable to common shareholders divided by average shareholder‘s equity. 3 Sum of after-tax earnings and after-tax interest expense, divided by weighted average capital employed. Capital employed is equal to the sum of equity, EGD preferred shares, deferred income taxes, deferred credits and total debt (including short-term borrowings). 4 Total debt (including short-term borrowings) divided by the sum of total debt and total equity inclusive of noncontrolling interests and redeemable noncontrolling interests. 5 Dividends per common share divided by adjusted earnings per common share. 6 Canadian Mainline includes deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries entering the Canadian Mainline in western Canada. 7 Volumes are for the Athabasca mainline and Waupisoo Pipeline and exclude laterals on the Regional Oil Sands System. 8 Number of active customers is the number of natural gas consuming EGD customers at the end of the period. 9 Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in EGD‘s franchise area. It is calculated by accumulating, for the fiscal period, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the GTA Five-Year Consolidated Highlights 171
Investor Information Common and Preference Shares The Common Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange and in the United States on the New York Stock Exchange under the trading symbol ENB. The Preference Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange under the trading symbols: Series A ENB.PR.A Series 1 ENB.PR.V Series B ENB.PR.B Series 3 ENB.PR.Y Series D ENB.PR.D Series 5 ENB.PF.V Series F ENB.PR.F Series 7 ENB.PR.J Series H ENB.PR.H Series 9 ENB.PF.A Series J ENB.PR.U Series 11 ENB.PF.C Series L ENB.PF.U Series 13 ENB.PF.E Series N ENB.PR.N Series 15 ENB.PF.G Series P ENB.PR.P Series R ENB.PR.T 2016 Enbridge Inc. Common Share Dividends Q1 Q2 Q3 Q4 4 4 4 Dividend $0.53 $ $ $ Payment date Mar 01 Jun 01 Sep 01 Dec 01 1 Record date Feb 16 May 16 Aug 15 Nov 15 2 SPP deadline Feb 23 May 25 Aug 25 Nov 24 3 DRIP enrollment Feb 08 May 09 Aug 08 Nov 08 1 Dividend record dates for Common Shares are generally February 15, May 15, August 15 and November 15 in each year unless the 15th falls on a Saturday or Sunday. 2 The Share Purchase Plan cut-off date is five business days prior to the dividend payment date. 3 The Dividend Reinvestment Program enrollment cut-off date is five business days prior to the dividend record date. 4 Amount will be announced as declared by the Board of Directors. Auditors PricewaterhouseCoopers LLP Registered Office Enbridge Inc. 200, 425 1st Street S.W. Calgary, Alberta, Canada T2P 3L8 Telephone: 403-231-3900 Facsimile: 403-231-3920 enbridge.com Registrar and Transfer Agent in Canada For information relating to share-holdings, share purchase plan,dividends, direct dividend deposit, dividend re-investment accounts and lost certificates, please contact: CST Trust Company P.O. Box 700 Station B Montreal, Quebec H3B 3K3 Toll free: 800-387-0825 canstockta.com CST Trust Company also has offices in Halifax, Toronto, Calgary and Vancouver. Co-Registrar and Co-Transfer Agent in the United States Computershare P.O. Box 30170 College Station, Texas 77842-3170 Toll free: 800-962-4285 Dividend Reinvestment and Share Purchase Plan Enbridge Inc. offers a Dividend Reinvestment and Share Purchase Plan that enables shareholders to reinvest their cash dividends in Common Shares and to make additional cash payments for purchases at the market price. Effective with dividends payable on March 1, 2008, participants in the Plan will receive a two percent discount on the purchase of common shares with reinvested dividends. Details may be obtained from the Investor Information section of the Enbridge website at or by contacting CST Trust Company directly. New York Stock Exchange Disclosure of Differences As a foreign private issuer, Enbridge Inc. is required to disclose any significant ways in which its corporate governance practices differ from those followed by United States companies under NYSE listing standards. This disclosure can be obtained from the Compliance subsection of the Corporate Governance section of the Enbridge website at enbridge.com Form 40-F The Company files annually with the United States Securities and Exchange Commission a report known as the Annual Report on Form 40-F. A link to the Form 40-F is available on the Investor Documents and Filings subsection of the Investment Center section of our website. 172 Enbridge Inc. 2015 Annual Report
Annual Meeting The Annual Meeting of Shareholders will be held in the Palomino Room at the BMO Centre at Stampede Park, 20 Roundup Way S.E., Calgary, at 1:30pm MDT on Thursday, May 12, 2016. A live audio webcast of the meeting will be available at enbridge.com and will be archived on the site for approximately one year. Webcast details will be available on the Company‘s website closer to the meeting date. Investor Inquiries If you have inquiries regarding the following: Additional financial or statistical information; Industry and company developments; Latest news releases or investor presentations; or Any other investment-related inquiries please contact Enbridge Investor Relations: Toll free: 800-481-2804 Office: 403-231-3960 investor.relations@enbridge.com Enbridge is committed to reducing its impact on the environment in every way, including the production of this publication. This report was printed entirely on FSC Certified paper containing post-consumer waste fibre and is manufactured using biogas energy. Safety Report to the Community Our 2015 Safety Report to the Community, which outlines our progress as we strive for 100% safety and zero incidents, is available at enbridge.com/safetyreport Corporate Social Responsibility Report Enbridge publishes an annual Corporate Social Responsibility Report. The 2015 report is available online at csr.enbridge.com Online Annual Report You can read our 2015 Annual Report online at enbridge.com/ar2015
The Global 100 Most Sustainable Corporations in the World highlights global corporations that have been most proactive in managing environmental, social and governance issues. In January 2016, Enbridge was named to the Global 100 for the seventh straight year, and 10th time overall. Enbridge is ranked No. 46 worldwide up from our No. 64 overall ranking in 2015 and third among Canadian corporations. In 2015, DJSI named Enbridge to both its World and North America index. The DJSI indices track the performance of large companies that lead the field in terms of sustainability, financial results, community relations and environmental stewardship. Enbridge has been included in the North America Index eight times in the past nine years, and named to the World Index six times, including the past four years running. 200, 425 1st Street S.W. Calgary, Alberta, Canada T2P 3L8 Telephone: 403-231-3900 Facsimile: 403-231-3920 Toll free: 800-481-2804 enbridge.com
Enbridge Inc.2015 Annual Review Consistency Strength Value
“Enbridge delivered strong results in 2015, one of the most challenging years the industry has ever faced. We believe that our solid business model and approach to investing capital and operating our assets positions us to continue to deliver value for our customers, stakeholders and shareholders—today and over the longer term.” –Al Monaco, President & CEO, Enbridge Inc. What sets us apart Resiliency Our low-risk business model delivers highly predictable results in all market conditions • Minimal exposure to commodity prices, foreign exchange and interest rates • Minimal volume risk; strong, long-term contracts and billing structures • Minimal credit risk; majority of revenues underpinned by strong counterparties Financial Strength and Flexibility • Strong investment-grade credit ratings • Ample liquidity; strong access to capital Strong Supply and Demand Fundamentals • Western Canada Sedimentary Basin is short pipeline capacity • Liquids Mainline at full capacity; 2.6 million barrels per day (bpd) in January 2016 • 800,000 bpd oil sands growth expected through 2019 Industry-Leading Growth Outlook (2015 – 2019) • $26-billion commercially secured growth capital program alone drives 12 – 14 percent annual cash flow per share growth and 10 – 12 percent annual dividend growth through 2019 • Additional new development opportunities provide further potential upside to cash ?ow and dividend growth Forward-Looking Information This Annual Review includes references to forward-looking information. By its nature this information applies certain assumptions and expectations about future outcomes, so we remind you it is subject to risks and uncertainties that affect every business, including ours. The more significant factors and risks that might affect future outcomes for Enbridge are listed and discussed in the “Forward-Looking Information” section on page 16 of this Annual Review and also in the risk sections of our public disclosure filings, including Management’s Discussion and Analysis, available on both the SEDAR and EDGAR systems at www.sedar.com and www.sec.gov/edgar.shtml, respectively. 1 Superior Total Shareholder Return Adjusted for 2011 2-for-1 stock split 1 Total Shareholder Return, assuming dividends are reinvested. 2 December 31, 2005 = zero for normalization calculation. 3 Compound Annual Growth Rate (CAGR) is the mean annual growth rate of an investment over a speci?ed time period. We have a consistent track record of delivering annual dividend increases, and our continuing goal is to deliver superior shareholder returns through capital appreciation and dividends. 1 Compound Annual Growth Rate (CAGR) is the mean annual growth rate of an investment over a speci?ed time period. 2015 Highlights Adjusted Earnings Adjusted Earnings Dividends Paid per Common Share per Common Share $1.9B $2.20 $1.86 Available Cash Flow ACFFO Growth Projects from Operations (ACFFO) per Common Share Placed into Service $3.2B $3.72 $8B
Contents Letter to Shareholders 2 2015 CSR Performance Highlights 12 Investor Information 17 ™ Life Takes Energy We’re committed to connecting people to the energy we all need to fuel our quality of life, and we’ve been doing so for more than 65 years. We connect people in three key ways: We Transport Energy Whether moving across town or across the country, no one is better equipped to deliver energy than Enbridge. We operate the world’s largest and most sophisticated transportation network for crude oil and liquids. We also have a growing ability to move natural gas and electricity. And we take pride in delivering it all with an unrelenting focus on safety. We Distribute Energy Our customers rely on the clean-burning natural gas we deliver to cook their food and heat their homes, water and workplaces. As owner and operator of Canada’s largest natural gas distribution company, we provide safe, reliable service to more than two million residential, commercial and industrial customers in Ontario, Quebec, New Brunswick and New York State. We Generate Energy We never stop thinking about the future of energy and sustainability, which is why we’re now a major and growing renewable energy company. Since our initial investment in 2002, we’ve invested approximately $5 billion in wind, solar, geothermal, hydropower and waste-heat power generation assets. Based on their gross generation capacity, our assets have the potential to supply more than one million homes with clean energy.
Letter to Shareholders Delivering Enbridge performed very well in 2015 because our business model is built to weather all the value market conditions. you count on In a challenging environment, Enbridge delivered solid results, we continued to grow and our outlook remains positive. By any measure, 2015 was a difficult year for the energy business. Our customers experienced historically low oil and gas prices, and rebalancing of global supply and demand is now expected to take longer. North American energy investment 1 dropped by US$69 billion or 35 percent over the previous year and capital markets have been highly volatile. At the same time, opposition to energy infrastructure development remains a challenge–making it difficult for oil and gas producers to gain access to North American and global market pricing. New governments in Alberta and Canada were elected on platforms of change. 1 Source: Barclays E&P Spending Outlook, January 13, 2016. 2 Enbridge Inc. Even with all of these challenges, our company performed very well in 2015 because our business model is built to weather this type of environment. Most important, we achieved excellent safety and operating performance and provided reliable energy transportation for our customers. In 2015, we delivered a record $1.9 billion in adjusted earnings or $2.20 per common share; $3.2 billion in Available Cash Flow from Operations (ACFFO) or $3.72 per common share; and we increased our dividend by 33 percent. We raised $5 billion in capital and maintained our financial strength and discipline so that we remain resilient through this downturn. We put into service 14 new projects valued at $8 billion, the majority on time and on budget. We also continue to develop new opportunities that will sustain our growth and position Enbridge for the future. How we’re meeting the challenges of the current business environment In the current business environment, it’s important that we remain disciplined in how we approach the business, operate our assets and invest capital. The following principles will continue to govern our approach. Focus on safety and operational reliability. This is our Number One priority because providing safe and reliable energy
Because Safety Matters Our annual Safety Report to the Community highlights our approach to safety, how we’re performing and what we are focusing on to be even safer in the future. The Report is available online at enbridge.com/ safetyreport 2014 Enbridge Safety Report to the Community Theworld’slargest Enbridge moves the energy and longestcrude we all count on to where we oilpipelinesystem, need it: our homes, businesses transportingover and communities near and far. Wegenerate Life takes energy and our job 2.2M is to move the energy you need barrelsperday. as safely as we possibly can. 1.6GW ofrenewableenergy from wind, solar and geothermal facilities across North America. Enough to power transportation drives value for our customers, and the public expects us to protect them and the environment. It’s this priority that guides everything we do and supports our vision to be North America’s leading energy delivery company. Minimize commodity price exposure and maintain a low-risk business model. For the vast majority of our business, the transportation and distribution tolls we charge don’t depend on the price of oil and gas. Where we do have some exposure to commodity price, interest rates and foreign exchange, we closely manage those risks. In addition, our existing assets and new investments are underpinned by strong commercial structures that generate stable and predictable financial results. Ensure capital investment discipline and access to capital. We invest significant amounts of capital, so it’s important that we allocate that capital to the best projects. We also need to ensure we can effectively fund new investments from internal sources or from the capital markets. We maintain a sound balance sheet, strong investment-grade credit ratings and significant liquidity to protect against disruptions in the capital markets. Focus on competitiveness. It’s even more important in today’s difficult business environment to focus on competitiveness. A big part of that is ensuring that we understand the supply and demand fundamentals that drive our business today and in the future. It also means keeping 2015 Annual Review 3
We’re confident in the strength and quality of our assets. Introducing ACFFO In 2015, we introduced a new financial metric–Available Cash Flow from Operations, or ACFFO–to complement adjusted EPS. ACFFO provides a greater degree of transparency into the cash flow generating capability of our businesses that drive shareholder value. We also think it’s a good way to measure our performance, especially with respect to growth potential and our capacity to pay dividends. For 2016 and going forward, ACFFO will be a key performance measure for the Company as a whole and the focus of our annual guidance. our costs in line and continually improving the effectiveness of what we do. In 2015, we closely managed our supply chain costs; reduced our workforce by five percent; and realized capital cost savings through the optimization of our Regional Oil Sands System–an initiative that will also deliver significant toll savings to our shippers. Developing our people. Our competitive advantage depends on the strength of our people. We focus on staff development at all levels of the organization and provide good opportunities for people to grow. We also make it a practice to rotate our management team members so we have a broad base of diverse and capable decision-making experience across the organization. We believe focusing on these priorities will translate into consistently strong ?nancial performance and value creation for our shareholders over the next ?ve years and well into the future. How we delivered value in 2015 Solid Results Our strong results in 2015 reflect the strength of our business model. Annual adjusted earnings were $1.9 billion or $2.20 per common share, a 16 percent increase over 2014. ACFFO for the full year 2015 was $3.2 billion or $3.72 per common share. That represented an increase of more than 23 percent year-over-year. Robust cash flow growth in turn supported strong dividend growth. In the first quarter, we increased our dividend by 33 percent, and announced in December a further 14 percent dividend increase effective with the first quarter of 2016. This was the st 21 consecutive year of increased dividends
for the Company. These increases re?ect strong year-over-year growth and the con?dence we have in our outlook. Equally important, our dividend growth has not come at the expense of our ?nancial strength as ACFFO coverage of our dividend remains very strong at approximately two times. Safe and Reliable Operations Over the past five years, we’ve invested $5 billion in the safety and integrity of our systems. We’ve transformed our approach to safety, focusing not just on improving our systems and processes, but importantly, on how each and every member of the Enbridge team thinks about safety. We continue to strengthen our safety culture and to hold ourselves accountable to each other and to our stakeholders. We’re seeing the outcome of our efforts. We achieved solid safety performance across all of our businesses in 2015. Our total recordable injury frequency–a measure of on-the-job safety–was the lowest in the past five years. All of our business units experienced strong performance in detecting and preventing releases from our pipelines and distribution systems, Record Throughputs 2.6Mbpd Our liquids mainline system started 2016 on a high note, delivering a record 2.6 million barrels per day (bpd) in January. We expect this level of performance to continue because our mainline is underpinned by strong supply and demand fundamentals. We’re seeing growing volumes from Canada’s oil sands; and we offer shippers unparalleled connectivity to key refining markets. In addition to connecting them to 3.5 million bpd of market demand, we provide them with stable, economical tolls so they can achieve the best netbacks. Over the past five years, we’ve invested $5 billion in the safety and integrity of our systems. 2015 Annual Review 5
even as we moved record volumes on our liquids systems. Being a leader in safety and protection of the environment is critical for our company’s ongoing business success. It helps us optimize system reliability and throughputs, which benefits our customers, and it helps sustain the growth of our company for the future. Execution of the Growth Plan We have placed $8 billion of projects into service since the beginning of 2015–an exceptional performance under any circumstances. Major accomplishments are highlighted below: • We continue to deliver new market access for our Liquids Pipelines customers. We’ve largely completed the Western Gulf Coast Access and Eastern Access programs and we made substantial progress with our Light Oil Market Access Program. Together, these three initiatives add 1.7 million barrels per day of incremental market access for our customers. In Gas Distribution, we’re nearing completion of our $0.9-billion Greater Toronto Area (GTA) Project to upgrade the backbone of Enbridge Gas Distribution’s system, supporting continued customer growth and enhancing reliability. In early 2016, we grew our Canadian natural gas midstream presence with the acquisition of the Tupper Main and Tupper West gas plants and associated pipelines in the Montney Region in northeastern B.C., one of the most attractive gas plays in North America. 1 Enbridge’s Commercially Secured Growth Projects/Estimated Costs Canadian $ billion, unless stated otherwise 2015 2017 Liquids Pipelines Gas Pipelines: Norlite Diluent Pipeline $0.9 Alberta Regional Infrastructure: Beckville Cryogenic Processing Facility US$0.2 Regional Oil Sands Optimization $2.6 AOC Hangingstone $0.2 Big Foot Oil Pipeline US$0.2 Other EGD Growth Capital $0.2 Sunday Creek Terminal Expansion $0.2 Eaglebine Gathering US$0.2 2018 Woodland Pipeline Expansion $0.7 Gas Distribution: Rampion Offshore Wind $0.8 Liquids Pipelines 2 Other EGD growth capital $0.2 Stampede Lateral US$0.2 Market Access Initiatives: Renewable Energy: Other EGD Growth Capital $0.2 Western U.S. Gulf Coast Access: Keechi Creek Wind Project US$0.2 2019 Associated Mainline Expansions $0.7 2016 Sandpiper Project US$2.6 Eastern Access: Heidelberg Lateral Pipeline US$0.1 U.S. Line 3 Replacement Program US$2.6 Line 9 Reversal $0.7 JACOS/Nexen Hangingstone $0.2 Canadian Line 3 Replacement Program $4.9 Light Oil Market Access: Line 6B Expansion US$0.3 U.S. Mainline Phase 2 (SA to 1200) US$0.5 Southern Access Extension US$0.6 Greater Toronto Area Project $0.9 Other EGD Growth Capital $0.2 Chicago Connectivity (Line 78) US$0.5 Aux Sable Expansion $0.1 U.S. Associated Mainline Expansions US$1.0 Tupper Main, Tupper West $0.5 Canadian Associated New Creek Wind Project US$0.2 Mainline Expansions $0.5 Other EGD Growth Capital $0.2 Line 9 Expansion $0.1 Edmonton to Hardisty Expansion $1.6 1 Enbridge’s commercially secured growth projects are discussed in greater detail beginning on page 35 of our Management’s Discussion and Analysis available at enbridge.com/ar2015. 2 Enbridge Gas Distribution. 6 Enbridge Inc.
In the offshore Gulf of Mexico, where we’re one of the largest natural gas and oil transporters, the Big Foot Gas Pipeline portion of the Walker Ridge Gas Gathering System and the Big Foot Oil Pipeline were installed on the sea floor and are awaiting installation of the upstream facilities by producers. In early 2016, we completed and placed into service the Heidelberg Oil Pipeline more than three months ahead of schedule. In Power Generation, we secured two new investments that further advance our strategy to extend and diversify our growth. The 400-MW Rampion Offshore Wind project in the UK is a natural extension of our existing wind business and a strategic entry point into an international market. The 103-MW New Creek Wind Project in West Virginia brings our net interests in renewable generating capacity to nearly 2,000 MW. Enbridge’s Major Projects (MP) group continues to be a source of competitive advantage in driving value for our customers and shareholders. MP’s execution capability combines disciplined processes, supply chain management, and the capacity and experience to get things done. Maintaining Financial Flexibility and Access to Capital We have the ?nancial ?exibility to successfully fund our growth projects in an effective and efficient manner. We generate signi?cant cash ?ow net of dividends, which can be redeployed into new investments. We have a strong balance sheet and access to a variety of low-cost funding sources. In 2015, we completed our Financial Strategy Optimization, which included an increase to the Company’s targeted dividend payout, as well as the $30.4-billion drop down of Enbridge’s Canadian Liquids Offshore Wind Our recent investment in Rampion provides us with a timely and effective entry point to the European offshore wind business. The business comes with strong market fundamentals, sound commercial underpinnings and attractive returns. Half of Europe’s generating capacity will come from renewables by 2025, and offshore wind will play an important role in that growth. Itisforecastthatoverthe nextdecade some €100 billion will be invested in the European offshore wind industry, and more than 20 gigawatts of offshore capacity is expected to be developed in Europe over the next ?ve years alone.
Our continuing goal is to deliver superior shareholder returns through capital appreciation and dividends. Pipelines business and certain Canadian renewable energy assets to our sponsored vehicle Enbridge Income Fund. We expect our sponsored vehicle strategy will further enhance the value of our capital program by providing access to diversified sources of low-cost funding. The strategy is also expected to improve our competitiveness to pursue new investment opportunities and to extend our industry-leading growth rate beyond 2019. In 2015, the Company directly and through its affiliates collectively raised more than $1.7 billion of equity capital and $3.7 billion of term debt capital. We believe the amount of capital required to support our commercially secured growth program is very manageable given the strong cash generating capability of our assets, our diversified sources of capital, solid investment-grade credit ratings and available liquidity of $10 billion as of the end of 2015. In late February 2016, we entered into an agreement with a group of Canadian and U.S. financial institutions to issue $2.3 billion of common shares–sufficient to fulfill equity funding 8 Enbridge Inc. requirements for our consolidated commercially secured growth program through the end of 2017. We remain focused on the execution and funding of our very attractive secured growth program, while maintaining the balance sheet strength needed to support our longer-term business plans. Disappointments Although we’re pleased with our results, 2015 was not without disappointments. Persistent low prices for natural gas and natural gas liquids continue to pose headwinds for our Gas Pipelines and Processing business. In Liquids Pipelines, earnings were impacted by the nearly year-long delay in receiving regulatory approval to bring the reversed Line 9 into service. We also anticipate delays on our Line 3 Replacement and Sandpiper projects. While we were pleased to receive greater clarity from the Minnesota Public Utilities Commission in January 2016 on the regulatory process for both projects, the timeline for approval will be extended and is expected to result in a delay to the in-service dates for both projects into early 2019. Despite our financial strength and our significant accomplishments in 2015, Enbridge was impacted, along with many of our peers, by broader market reaction to commodity prices, interest rates and the continuing challenges facing the energy sector. We’ve experienced volatility in our share price and we’re disappointed Enbridge’s solid attributes were not reflected in the Company’s valuation in 2015, resulting in negative shareholder return of 20 percent. That said, our three-, five- and 10-year total shareholder return well exceeds the performance of broader market indices. How we will deliver value in the future Our commercially secured growth program alone, in combination with our existing business, is expected to deliver very attractive compound average annual growth in ACFFO per share of 12 – 14 percent over our five-year (2015 – 2019) planning horizon.
Our 50-MW Silver State North solar project in Nevada generates enough emission-free energy to serve the needs of more than 11,000 homes. We believe that the long-term “ fundamentals of energy are very strong and that our business will continue to thrive. That should readily support a base level of dividend growth in the range of 10 – 12 percent. However, cash ?ow and dividend growth could well exceed these levels depending on the success we have in securing and funding new growth opportunities beyond those that have been commercially secured. We will continue to evaluate new investments that diversify and extend our growth and build an opportunity set for the future. While we see further opportunities to grow our Liquids Pipelines business, we are increasingly looking to develop and grow our new platforms in renewable power generation, natural gas infrastructure and gas-?red generation, power transmission and energy marketing, as well as international opportunities to invest in energy infrastructure in select regions outside Canada and the United States. As always, investments will need to pass stringent criteria and fit within our business model. We will continue to focus most of our attention on organic growth and assets that enhance our strategic position. Given the current environment, we’ll be lowering the microscope even further to make sure that we’re deploying capital to the most optimal projects. When we decide to move on opportunities, we’ll bring those forward with executable and effective funding sources identified. There’s no doubt that the current energy environment is challenging, but we believe that the long-term fundamentals of energy are very strong and that our business will continue to thrive. We believe global energy 2015 Annual Review 9
The majority of Enbridge Gas Distribution’s vehicle fleet runs on natural gas, thereby reducing greenhouse gas emissions. Helping Customers Conserve Energy Enbridge Gas Distribution (EGD) is helping its more than two million residential, commercial and industrial customers to use energy wisely through a wide range of demand-side management (DSM) programs, including energy-efficiency audits, financial rebates for adopting energy-saving equipment, and energy reports to help consumers better understand their energy usage. Cumulatively since 1995, EGD’s DSM programs have saved approximately 9.6 billion cubic meters of natural gas and reduced carbon dioxide equivalent emissions by 18 million tonnes, which is similar to taking approximately 3.5 million cars off the road for a year or serving approximately four million homes for a year. 10 Enbridge Inc. demand will continue to grow by about 30 percent over the next two decades, driven by global population growth, increasing urbanization to larger-scale cities and the desire for increasing living standards, particularly in developing nations. With this level of energy growth, it’s critical that we continue to develop all sources of energy supply in a sustainable way. North America has tremendous unconventional oil and gas reserves that will help meet the world’s energy needs. We also possess the skills and technology to ensure that these resources are competitive and developed sustainably. Enbridge is a big part of that in a couple of ways. First, we have a number of projects under way that will help our resources get to the best markets and to consumers who need that energy. There’s no doubt that pipelines remain the lowest cost, most efficient and safest way to transport oil and natural gas. We see continued opportunities to expand
and extend our pipeline systems to help meet North America’s energy needs and contribute to energy security, as well as build connectivity to coastal markets that enable exports.
Second, we see significant opportunity in the transition to a lower carbon future as we look to expand and diversify our energy businesses. It’s an opportunity we recognized more than a decade ago when we first invested in wind power generation and
it’s one we’re actively pursuing today as one of Canada’s largest renewable energy companies. With our established natural gas and power generation businesses, Enbridge is well positioned to play a leadership role in the shift in the energy supply mix, and transition to a lower-carbon future.
2015 was one of the most challenging years our industry has faced in decades. Enbridge has persevered–and we’re well positioned to withstand the current turbulent market environment.
Acknowledgements Enbridge has a highly capable and energetic team of people with a proven track record of delivering value to customers and shareholders alike. We thank them for their outstanding work in 2015 in building the Company and putting it in a strong position for future growth. In 2015, Lorne Braithwaite and Charles Schultz retired from the Board and we thank them for their valuable contribution to the Board’s deliberations over the years. We also welcomed to the Board Rebecca Roberts, who was President of Chevron Pipe Line Company from 2006 to 2011 and President of Chevron Global Power Generation from 2003 to 2006. We’re striving for leadership in safety and environmental stewardship. In a turbulent environment, Enbridge’s reliable and proven business model sets us apart 2015 was a year of challenge and change for the energy sector. As we begin 2016, the energy landscape continues to evolve–driven by changing dynamics of supply and demand, and shaped by the imperative to protect our environment while meeting our global energy needs. This isn’t new to us. We’re managing our business to weather these kinds of tough conditions, we’re very mindful of current market conditions and we will remain vigilant. We’re confident in the strength and quality of our assets, and we believe our approach–and the principles we’ve adhered to over the years–uniquely position Enbridge to manage through these turbulent times and to continue to deliver the value you count on today and over the long term. Al Monaco David A. Arledge President & Chair Chief Executive Officer Board of Directors March 8, 2016
2015 CSR Performance Highlights Corporate Social Responsibility The world isn’t standing still, and neither are we. We’re working to meet the high standards the public expects of us—putting safety and environmental protection first; being open and transparent about our performance; providing good jobs to a talented workforce; and striving to build strong relationships with communities, Aboriginal and Native American groups and stakeholders everywhere we operate. We’re also very aware that as a North American leader in energy infrastructure systems that deliver oil, natural gas and renewable energy, we are uniquely positioned to help bridge the transition to a lower-carbon future. Energy systems are changing and so are we. But one thing won’t change. We will keep fuelling people’s quality of life, because life takes energy. Presented here is a summary of our 2015 CSR performance. You can read our entire 2015 CSR & Sustainability Report online at csr.enbridge.com The report covers the governance, social, environmental and economic issues that are most important to our stakeholders, our business today and our strategic priorities. Every year, we work to make our sustainability reporting more robust, transparent and useful for all readers, internal and external to the company. It’s important to us because sharing our sustainability successes, challenges and opportunities is one of the ways we hold ourselves accountable for our performance on the social and environmental issues that are integral to the future of our business and everyone who depends on us. The year-long sustainability reporting process that underpins the development of content for this report also helps us identify what’s next and how we can do better in the future. 2015 at a Glance Liquids Pipelines (LP) System Integrity and Leak Detection $787million 1 In 2015, we invested more than $787 million in systems integrity and leak detection programs for our liquids systems in Canada and the U.S. 1 Includes Canada and U.S. dollar amounts 141 pipeline inspections in 2015 across our LP system Renewable + Alternative Energy $5B invested in renewable and alternative energy projects since 2002 >2.8B barrels of crude oil and liquids delivered by LP <280 bbls spilled in 2015, of which 95 percent were contained within our facilities 17.2B bbls is the amount of crude oil and liquids our LP system delivered from 2006 to 2015, with a safe delivery percentage of 99.9995 Nearly 2,800MW of gross generating capacity (Enbridge Inc. and subsidiaries’ interests: 2,000 MW)
Based on gross generation ?gures, our portfolio of renewable power assets has the potential to supply more than one million homes with clean energy. Wind Gross Capacity 2,568MW 1 Our Interest 1,820MW 1 Enbridge Inc. and subsidiaries. Solar Gross Capacity 150MW 1 Our Interest 150MW Geothermal Gross Capacity 23MW 1 Our Interest 9MW Waste Heat Recovery Gross Capacity 34MW 1 Our Interest 17MW Hydro Power Gross Capacity 2MW 1 Our Interest 1MW 2015 Annual Review 13
2015 CSR Performance Highlights Fitness of Enbridge’s Liquids Systems and Leak Detection Our goal is to achieve industry leadership in the safety and reliability of our pipelines and facilities, and protection of the environment. Asset Integrity and Reliability LP In-Line Inspection Runs 13 14 15 Having invested billions of dollars in the safety and reliability of our systems over the past five years, we are beginning to decrease the number of the in-line and other inspections that we conduct. However, our commitment to the safety of our systems is not decreasing. Advancements in predictive (reliability) modeling, data analysis and improved efficiency in carrying out our activities are enabling us to continually enhance the safety and integrity of our systems while optimizing our time and costs. LP Spills, Leaks and Releases Over the past decade, our LP system delivered 17.2 billion barrels of crude oil and liquids with a safe delivery record of 99.9995 percent. Summary Profile of 2015 LP Spills One incident had a volume of 100 barrels or greater. In 38 of the 45 incidents, a total of 264 barrels of oil were spilled and contained within our facilities. In the other seven incidents, a total of 15 barrels were spilled on our pipeline rights-of-way outside our facilities. LP Spills History (2010 – 2015) Energy & Climate Change We believe the world must find new ways to meet increasing demand for energy from a growing global population while limiting the greenhouse gas (GHG) emissions that cause climate change. GHG Emissions and Energy Consumption 1 2014 GHG Emissions Tonnes of carbon dioxide equivalent (tCO e) 2 1 2015 GHG emissions data will be available in mid 2016. 2 Increase is largely due to greater electricity use by LP due to increased delivery volumes. 3 Indirect GHG emissions are those that result from an organization’s activities, but that occur at sources not owned or controlled by the organization. 1 2014 Energy Consumption Gigajoules (GJ) 1 2015 energy consumption data will be available in mid 2016. 2 Increase is largely due to greater electricity use by LP due to increased delivery volumes.
Human Health & Safety We are committed to ensuring that everyone returns home safely at the end of the day, and that our assets are operated safely. Our commitment is based on caring for our employees, contractors, customers, communities and the environment. Recordable and Lost-Days Injuries As we strive to achieve industry leadership in pipeline system integrity, process safety and environmental responsibility, we also strive to be a leader in human health and safety. 2013 1.14 0.17 0/1 2014 0.94 0.11 1/1 0.66 0.12 2015 0/0 Recordable Injuries Lost-Days Injuries Fatal Incidents for 200,000 employee per 200,000 employee Employees/ hours worked hours worked Contractors Supply Chain and Procurement We recognize that our supply chain plays a key role in helping fuel people’s quality of life, which is why we are building strong relationships with our suppliers and developing a comprehensive and consistent approach to supply chain management. 96 percent of steel pipe purchased by our Major Projects group was made of 100 percent recycled content (212,000 tonnes) Economic Impact and Benefits In 2015, we invested over $19 million in more than 750 charitable, non-profit and community organizations, and more than $63 million on procuring goods and services from Aboriginal businesses, contractors and suppliers. Through the taxes we pay to governments and the salaries we pay to employees and contractors—and through our capital and operating & administration expenses—we also have a positive economic impact on the countries and communities in which we operate. Economic Benefits 1 TaxesPaidtoGovernments Base Salaries Capital Expenses Operating & Administration Expenses $266M $631M $4.1B $1.8B $341M US$227M $3.2B 1 In Canada, payments to governments include property taxes, income taxes and other taxes. In the U.S., they include property taxes, sales & use taxes, income taxes and other taxes. 2015 Annual Review 15
Forward-Looking Information / Non-GAAP Measures Forward-Looking Information Forward-looking information, or forward-looking statements, have been included in this Annual Review to provide information about Enbridge and its subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ’’anticipate’’, ’’expect’’, ’’project’’, ’’estimate’’, ’’forecast’’, ’’plan’’, ’’intend’’, ’’target’’, ’’believe’’, “likely” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included in this document include, but are not limited to, statements with respect to the following: expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected ACFFO or expected ACFFO per share; expected future cash flows and sources thereof; access to capital; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; dividend payout policy and dividend payout expectation; expectations regarding the impact of the recently completed transaction whereby Enbridge transferred its Canadian Liquids Pipeline Business and certain other Canadian renewable assets (Canadian Restructuring Plan) to Enbridge Income Fund; expectations regarding commodity prices; supply forecasts; expected global demand for energy; expected sources of energy; expected need for new pipeline capacity; expected production from oil sands projects; expectations in respect of the European wind industry; expected European energy requirements; business plans of Enbridge entities; and diversification of Enbridge’s business. Although Enbridge believes these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, NGL and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; expected exchange rates; inflation; interest rates; availability and price of labour and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for Enbridge’s projects; anticipated in-service dates; weather; the impact of the Canadian Restructuring Plan and dividend policy on Enbridge’s future cash flows; credit ratings; capital project funding; expected earnings/(loss) or adjusted earnings/ (loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows and expected future ACFFO or expected ACFFO per share; and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for Enbridge’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which Enbridge operates and may impact levels of demand for Enbridge’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings/(loss), adjusted earnings/(loss) and associated per share amounts, ACFFO and associated per share amounts, the impact of the Canadian Restructuring Plan on Enbridge or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer and regulatory approvals on construction and in-service schedules. Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Canadian Restructuring Plan, dividend policy, operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, public opinion, changes in tax law and tax rate increases, exchange rates, interest rates, commodity prices and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this Annual Review and in Enbridge’s filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this Annual Review 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 Enbridge’s behalf, are expressly qualified in their entirety by these cautionary statements. Non-GAAP Measures This Annual Review contains references to adjusted earnings/(loss) and ACFFO. Adjusted earnings/(loss) represents 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 in the Company’s Management’s Discussion and Analysis. Adjusting items referred to as changes in unrealized derivative fair value gains and losses are presented net of amounts realized on the settlement of derivative contracts during the applicable period. ACFFO is defined as cash flow provided by operating activities before changes in operating assets and liabilities (including changes in regulatory assets and liabilities and environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. Management believes the presentation of adjusted earnings/(loss) and ACFFO provide useful information to investors and shareholders as they provide increased transparency and insight into the performance of the Company. Management uses adjusted earnings/(loss) to set targets, and to assess the performance of the Company. Management also uses ACFFO to assess the performance of the Company and to set its dividend payout target. Adjusted earnings/(loss), adjusted earnings/ (loss) for each segment and ACFFO are not measures that have standardized meaning prescribed by accounting principles generally accepted in the United States of America (U.S. GAAP) and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers.
Annual Meeting The Annual Meeting of Shareholders will be held in the Palomino Room at the BMO Centre at Stampede Park, 20 Roundup Way S.E., Calgary, at 1:30pm MDT on Thursday, May 12, 2016. A live audio webcast of the meeting will be available at enbridge.com and will be archived on the site for approximately one year. Webcast details will be available on the Company’s website closer to the meeting date. Registrar and Transfer Agent in Canada For information relating to share- holdings, shareholder investment plan, dividends, direct dividend deposit, dividend re-investment accounts and lost certificates, please contact: CST Trust Company P.O. Box 700 Station B Montreal, Quebec, Canada H3B 3K3 Toll free: 800-387-0825 canstockta.com CST Trust Company also has offices in Halifax, Toronto, Calgary and Vancouver. Co-Registrar and Co-Transfer Agent in the United States Computershare P.O. Box 30170 College Station, Texas U.S.A. 77842-3170 Toll free: 800-962-4285 Investor Inquiries If you have inquiries regarding the following: Additional financial or statistical information; Industry and company developments; Latest news releases or investor presentations; or Any other investment-related inquiries please contact Enbridge Investor Relations: Toll free: 800-481-2804 Office: 403-231-3960 investor.relations@enbridge.com Common and Preference Shares The Common Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange and in the United States on the New York Stock Exchange under the trading symbol “ENB.” The Preference Shares of Enbridge Inc. trade in Canada on the Toronto Stock Exchange under the trading symbols: Series A – ENB.PR.A Series 1–ENB.PR.V Series B–ENB.PR.B Series 3–ENB.PR.Y Series D–ENB.PR.D Series 5–ENB.PF.V Series F – ENB.PR.F Series 7–ENB.PR.J Series H–ENB.PR.H Series 9 –ENB.PF.A Series J–ENB.PR.U Series 11–ENB.PF.C Series L–ENB.PF.U Series 13–ENB.PF.E Series N – ENB.PR.N Series 15–ENB.PF.G Series P–ENB.PR.P Series R – ENB.PR.T 2016 Enbridge Inc. Common Share Dividends Q1 Q2 Q3 Q4 4 4 4 $– Dividend $0.53 $ – $ – Payment date Mar 01 Jun 01 Sep 01 Dec 01 1 Record date Feb 16 May 16 Aug 15 Nov 15 2 SPP deadline Feb 23 May 25 Aug 25 Nov 24 3 DRIP enrollment Feb 08 May 09 Aug 08 Nov 08 1 Dividend record dates for Common Shares are generally February 15, May 15, August 15 and November 15 in each year unless the 15th falls on a Saturday or Sunday. 2 The Share Purchase Plan cut-off date is five business days prior to the dividend payment date. 3 The Dividend Reinvestment Program enrollment cut-off date is five business days prior to the dividend record date. 4 Amount will be announced as declared by the Board of Directors. Safety Report to the Community Our 2015 Safety Report to the Community, which outlines our progress as we strive for 100% safety and zero incidents, is available at enbridge.com/safetyreport Corporate Social Responsibility Report Enbridge publishes an annual Corporate Social Responsibility Report. The 2015 report is available online at csr.enbridge.com Online Annual Report You can read our 2015 Annual Report online at enbridge.com/ar2015 Enbridge is committed to reducing its impact on the environment in every way, including the production of this publication. This report was printed entirely on FSC® Certi?ed paper containing post-consumer waste ?bre and is manufactured using biogas energy.
The Global 100 Most Sustainable Corporations in the World highlights global corporations that have been most proactive in managing environmental, social and governance issues. In January 2016, Enbridge was named to the Global 100 for the seventh straight year, and 10th time overall. Enbridge is ranked No. 46 worldwide–up from our No. 64 overall ranking in 2015–and third among Canadian corporations. In 2015, DJSI named Enbridge to both its World and North America index. The DJSI indices track the performance of large companies that lead the field in terms of sustainability, financial results, community relations and environmental stewardship. Enbridge has been included in the North America Index eight times in the past nine years, and named to the World Index six times, including the past four years running. 200, 425 – 1st Street S.W. Calgary, Alberta, Canada T2P 3L8 Telephone: 403-231-3900 Facsimile: 403-231-3920 Toll free: 800-481-2804 enbridge.com