Enbridge Annual Report 2016

Plain-text annual report

Enbridge Inc. 2016 Annual Report Contents Company Snapshot 1 Investment Proposition 2 Letter to Shareholders 4 CSR Performance Highlights 10 Corporate Governance 11 Investor Information 182 Bringing new energy to energy “Today, there’s a new energy around energy, and Enbridge is better positioned than ever to be a leader in North America’s energy future. Our combination with Spectra Energy has made us an even bigger force in energy infrastructure in North America, and sets us up for decades to come.” – Al Monaco, President & CEO, Enbridge Inc. Life Takes Energy® We’re committed to connecting people to the energy we all need to fuel our quality of life, and we do that in three key ways: We Transport Energy 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; and we move approximately 20 percent of all natural gas consumed in the U.S. 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 two largest natural gas distribution companies, we provide safe, reliable service to 3.5 million residential, commercial and industrial customers in Ontario, Quebec, New Brunswick and New York State. We Generate Energy Our focus on the future of energy and sustainability has led us to become a major and growing renewable energy company. Since 2002, we’ve invested over $5 billion in wind, solar, geothermal, hydropower and waste-heat power generation assets. We also have a growing position in the European offshore wind generation market. Based on their gross generation capacity, our assets have the potential to supply more than one million homes with clean energy. 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 beginning on page 25 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. Company Snapshot Combining Strength with Strength With the successful completion of our combination with Spectra Energy Corp (Spectra Energy) on February 27, 2017, Enbridge is now the largest energy infrastructure company in North America. Scale and size Unparalleled growth program $166B enterprise value1 $27B secured + $48B potential Stable and predictable revenue Industry-leading cash ﬂow growth Superior annual dividend growth >95% revenue protected from volume and price risk2 12 – 14% ACFFO3 per share CAGR4 for 2014 – 2019 10 – 12% expected through 2024 Diversiﬁed assets Balance between crude oil and natural gas; expanding renewables business 1 Canadian dollars, as at February 22, 2017. 2 >95 percent take-or-pay or similar contracts, or regulated cost-of-service assets. 3 Available Cash Flow From Operations. 4 Compound Annual Growth Rate. Zama Zama Peace River Peace River ort St. John Fort Fort McMurray McMurray Cheecham Cheecham Edmonto Hardisty Hardisty Kerrobert Kerrobert C A N A D A Vancouver ancouver Seattle Seattle Lethbridge Lethbridge Regina Regina Portland Portland Great Falls Great Falls MinotMinot Edgar Edgar Gretna Gretna Clearbrook Clearbrook Casper Casper Gurley Gurley U N I T E D S T A T E S U N I T E D S T A T E S O F A M E R I C A O F A M E R I C A M E X I C O Flanaga hicago Toledo Toledo Patoka Patoka Wood Wood River River Nashville Nashville Saltville Saltville ushi NewNew a Montreal Montreal o er Buffalo Buffalo Leidy Leidy Boston n Boston Boston Irish Sea North Sea Hamburg UNITED KINGDOM THE English Channel Eoliennes Offshore Eoliennes Offshore des Hautes Falaises des Hautes Falaises BELGIUM GERMANY ParisParis FRANCE Liquids Pipelines Natural Gas Transmission Pipelines Natural Gas Gathering Pipelines Gas Processing Plants Enbridge Gas Distribution and Affiliates Service Territory Union Gas Service Territory Crude Storage and Terminals Gas Storage Facility Natural Gas Liquids Storage Propane Terminals Liqueﬁed Natural Gas Rail Trucking Facility Power Transmission Wind Assets Wind Assets in Development Solar Assets Waste Heat Recovery Geothermal Power Hydroelectric Power Assets 2016 Annual Report 1 Investment Proposition How We Deliver Value to Our Shareholders While the size and reach of Enbridge has grown as a result of our combination with Spectra Energy, our value proposition to shareholders remains the same –delivering superior returns through the strength of our low-risk business model. This has driven our success in the past and it will continue to do so in the future. Reliable Business Model Industry - Leading Growth Signiﬁcant Dividend Income Superior Shareholder Returns What Sets Us Apart Resiliency Our low-risk business model delivers highly predictable results in all market conditions • Minimal exposure to market 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 Strong Supply and Demand Fundamentals • Liquids: Western Canada Sedimentary Basin is short pipeline capacity, with 600,000 barrels per day oil sands growth expected through 2020 • Natural Gas: Connectivity to major markets; steady long-term growth from demand into the U.S. northeast, southeast and Gulf Coast Industry-Leading Growth Outlook • $27-billion commercially secured growth capital program alone drives 12 –14 percent annual ACFFO per share growth rate (2014 – 2019) • Additional $48 billion in future projects supports further potential upside to cash ﬂow and annual 10 –12 percent dividend growth through 2024 Financial Strength and Flexibility • Strong, investment-grade credit ratings • Ample liquidity, strong access to capital • Renewables: Renewable power expected to account for a larger share of the collective energy mix as demand for lower-carbon energy sources grows Multiple Strategic Platforms for Growth North American Liquids Pipelines Highly predictable growing cash ﬂow with signiﬁcant further upside optionality North American Gas Pipelines Positioned for sustained demand-pull organic growth for the foreseeable future Canadian Midstream Positioned to compete with Canada’s leading midstream players on gas and NGL midstream infrastructure Utilities Utility businesses generate attractive returns and steady growth; compelling platform for extension to electric utilities 2 Enbridge Inc. U.S. Midstream Positioned to provide integrated gas/liquids midstream services across the hydrocarbon value chain Renewable Power U.S. presence and utility customer base enhances growth opportunities; Enbridge is a top-10 player in renewable energy in North America 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights 2016 Highlights Adjusted Earnings Adjusted Earnings Adjusted Earnings Adjusted Earnings Adjusted Earnings Available Cash Flow from Operations (ACFFO) Available Cash Flow from Operations (ACFFO) Available Cash Flow from Operations (ACFFO) Available Cash Flow from Operations (ACFFO) Available Cash Flow from Operations (ACFFO) Dividends Paid per Common Share Dividends Paid per Common Share Dividends Paid per Common Share Dividends Paid per Common Share Dividends Paid per Common Share $2.1$2.1 $2.1B $3.7B $3.7$3.7 $3.7$3.7 $2.1$2.1 $3.7$3.7 $2.1$2.1 $3.7$3.7 $3.7$3.7BB $2.1$2.1 $2.1$2.1 $3.7$3.7 $2.1$2.1 BB BB BB BB BB $2.12$2.12 $2.12 $2.12$2.12 $2.12$2.12 $2.12$2.12 $2.12$2.12 $2.12$2.12 Adjusted Earnings per Common Share Adjusted Earnings per Common Share Adjusted Earnings per Common Share ACFFO per Common Share ACFFO per Common Share ACFFO per Common Share Year-over-Year Dividend Growth $2.28 $2.28 $2.28 $4.08 $4.08 $4.08 $2.28 $2.28 $4.08 $4.08 $2.28 $2.28 $4.08 $4.08 $2.28 $2.28 $4.08 $4.08 $2.28 $2.28 $4.08 $4.08 $2.28 $2.28 $4.08 $2.28 $4.08 $2.28 $4.08 $4.08 $2.28 $2.28 $4.08 $2.28 $4.08 $2.28 $4.08 $2.28 $4.08 $2.28 $4.08 $4.08 14% 14%14% 14%14% 14%14% 14%14% 14%14% 14%14% 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. 20-Year Dividend Growth Canadian dollars per share $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 2 0 - y e a r C AG R 1 = 1 1 . 2 % %%%%%% %%%%%%%%1 . 21 . 21 . 21 . 2 %%%%1 . 21 . 21 . 21 . 21111 1 . 21 . 21 . 21 . 2 1111 G RG RG RG R 11111111 1111 6 9 9 1 7 9 9 1 8 9 9 1 9 9 9 1 0 0 0 2 1 0 0 2 2 0 0 2 3 0 0 2 4 0 0 2 5 0 0 2 6 0 0 2 7 0 0 2 8 0 0 2 9 0 0 2 0 1 0 2 1 1 0 2 2 1 0 2 3 1 0 2 4 1 0 2 5 1 0 2 6 1 0 2 1 Compound Annual Growth Rate of an investment over a speciﬁed time period. Superior Total Shareholder Return1 300% Enbridge Inc. S&P/TSX Composite Index 200% 100% 14.5% CAGR2 4.7% CAGR2 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 1 Total shareholder return inclusive of share price appreciation, assuming dividends are reinvested. Chart represents data from January 1, 2007 to December 31, 2016. 2 Compound Annual Growth Rate of an investment over a 10-year time period. 2016 Annual Report 3 Letter to Shareholders Positioning Enbridge for the Future “We have the size, scale and scope to sustain our growth well into the future.” –Al Monaco, President & CEO, Enbridge Inc. Al Monaco President & Chief Executive Officer There’s a new energy around energy As we begin 2017, commodity prices have stabilized and we’re seeing increasing conﬁdence in a sustained recovery– that’s good news for our customers and drives the need for more energy infrastructure. Longer term, the outlook for energy and infrastructure is positive. World demand for energy is expected to grow by 30 percent by 2040, and to meet that demand we’re going to need all sources of supply, including traditional fuels and renewable energy. The integrated North American energy market–with its abundant energy resources, world-class technology and availability of capital–has a powerful competitive advantage when it comes to meeting global energy needs. That advantage becomes even more powerful when enabled by new infrastructure that creates timely access to markets. 4 Enbridge Inc. While we continue to face opposition to energy development, we’re seeing a more constructive debate taking place on the merits of energy. There’s growing understanding that a balanced approach is possible: that we can develop our energy resources and generate economic prosperity, while at the same time protect our environment. Enbridge was already well-positioned to beneﬁt from these dynamics, but on February 27, 2017, we became even stronger when we successfully closed our combination with Spectra Energy to create North America’s largest energy infrastructure company and one of the world’s largest publicly traded energy companies –valued at $166 billion1. With this one strategic move, we’ve brought the highest-quality liquids and natural gas infrastructure franchises on the continent together under one roof– with the largest scale and highest-quality assets, industry-leading growth capital program, a strong ﬁnancial position and an exceptional group of people. We have the size, scale and scope to sustain our growth well into the future, creating long-term value for our shareholders for decades to come. Today, we’re better positioned than ever to not only extend and diversify Enbridge’s growth over the next couple of decades, but also to be a leader in North America’s energy future. In doing so, we’re building on the same value proposition that got us to this point–delivering strong growth and steady and growing income within a low-risk business model. 1 Enterprise value as at February 22, 2017. Delivering solid results in 2016 Enbridge’s reliable business model again delivered solid ﬁnancial results in 2016 despite signiﬁcant industry challenges, including the commodity- price downturn, a difficult project- execution environment and extreme wildﬁres in northeastern Alberta in May that curtailed oil sands production. Annual adjusted earnings increased to $2.1 billion or $2.28 per common share. Adjusted earnings before interest and income taxes (EBIT) grew to $4.7 billion. Available Cash Flow from Operations (ACFFO) for the full year 2016 was $3.7 billion or $4.08 per common share, a 10-percent increase over 2015. Our strong results reﬂected positive contributions from our largest lines of business, and were largely driven by growth capital that we’ve put into service over the past two years. Importantly, they also reﬂect our strong performance from safety and operational reliability. We won’t ever let up on this – our most important priority–and the work our teams have done to achieve industry leadership is paying off. Delivering consistent and dependable dividend growth is core to our shareholder value proposition and a direct reﬂection of our low-risk business model, which has proved its ability to perform well in all market conditions. We increased the dividend 14 percent in 2016; and in January, we announced a further 10-percent increase effective the ﬁrst quarter of 2017, marking the 22nd consecutive year of increased dividends for the Company. These dividend increases reﬂect the strength of our base business, together with the impact of $2 billion in growth capital projects that we brought into service during 2016 and our expectation of additional Enbridge growth projects coming into service in 2017. Following the combination with Spectra Energy, we believe the ﬁnancial outlook of the combined company will support a further ﬁve-percent increase in our quarterly dividend in 2017 (above and beyond the 10-percent increase announced in January 2017), which we expect to conﬁrm when we announce our ﬁrst- quarter 2017 results in May. Building on our core strengths Our businesses performed well overall in 2016. The most signiﬁcant contribution to our 2016 results came from our Liquids Pipelines segment. During the year, our liquids Mainline ran very close to full 2016 Annual Report 5 Letter to Shareholders Mainline Advantage Enbridge’s liquids Mainline system offers shippers and the Company several competitive advantages. Upstream, our Mainline is connected to one of the most proliﬁc oil producing regions in the world–the Western Canada Sedimentary Basin (WCSB). Based on the most recent forecast from the Canadian Association of Petroleum Producers, we expect about 600,000 bpd of supply growth through 2020, with an additional 800,000 bpd of growth through 2030. Downstream, our Mainline is connected to many of the best markets in North America and directly to 3.5 million bpd of reﬁning capacity and connected pipelines. The scale and reach of the Mainline system generates very stable and competitive tolls for Canadian producers, which is critical in the current low-oil-price environment as it enables them to achieve the best netbacks. Our ability to bring on incremental capacity through Mainline system optimizations and execution of our downstream market- access strategies over the past ﬁve years has provided our customers with tremendous value. Looking ahead, the Mainline continues to provide opportunities for low-cost capacity expansion to match WCSB supply growth through additional integrity work, system optimization and the addition of pump stations. 6 Enbridge Inc. utilization, although throughputs were impacted by the Alberta wildﬁres. In December, we delivered a record 2.6 million barrels per day (bpd) ex-Gretna at the Canada-U.S. border; and in January 2017, volumes ex-Gretna set another record of 2.65 million bpd. Our ability to achieve this utilization doesn’t just happen. It’s driven by our maintenance and integrity program and careful planning to ensure high reliability and reduced downtime. We made substantial progress on our secured growth capital program: • The Canadian federal government approved the Canadian portion of our $7.5-billion Line 3 Replacement (L3R) Program, and we continue to make progress towards regulatory approvals in the U.S. Scheduled to be in service in 2019, this replacement program will support the safety and operational reliability of the Mainline system, enhance ﬂexibility, allow us to optimize throughput on the Mainline system and restore approximately 370,000 bpd of capacity from Western Canada into Superior, Wisconsin, providing the most timely and reliable solution for transporting western Canadian crude oil to the Chicago, U.S. Gulf Coast, eastern U.S. and Canadian reﬁnery markets. The largest project in our history, the L3R Program has also involved our most extensive outreach ever to Indigenous and Native American groups and communities, and we will continue to engage with them as we move beyond regulatory approval. • We placed the Line 6B Expansion Project into service, completing the ﬁnal component of our Eastern Access Program, which is providing increased access to reﬁneries in the upper Midwest U.S. and eastern Canada. • Enbridge Gas Distribution Inc. (EGD) completed the $0.9-billion Greater Toronto Area (GTA) Project, which has enabled EGD to meet the demands of growth in the GTA and continue the safe and reliable delivery of natural gas to current and future customers. • The 103-megawatt (MW) New Creek Wind Project in West Virginia entered service in December, further advancing our key corporate priority of growing our renewable generation platform. • In January 2017, we placed into service the Athabasca Pipeline Twin project, which is the ﬁrst phase of our $2.6-billion Regional Oil Sands Optimization Project to connect growing oil sands supply to our Mainline system. We also acquired assets to further strengthen our liquids pipelines, gas pipelines and renewables businesses, including: in the North Sea in partnership with the state-owned German utility, Energie Baden-Wurttenberg, and is expected to be in service in late 2019. • The acquisition of the Tupper natural gas processing plants and associated pipelines in the Montney region of northeastern British Columbia for $0.5 billion, enhancing our natural gas footprint in one of the most attractive gas plays in North America. During the balance of 2017, we expect to complete and put in service $13 billion in growth projects, including the remaining Regional Oil Sands Optimization projects, the 249-MW Chapman Ranch Wind Project in Texas and the Sabal Trail Transmission project. • Investment in a 50-percent interest in Eolien Maritime France SAS (EMF), a French offshore wind development company, to co-develop three large- scale offshore wind farms off the coast of France that would produce a combined 1,428 MW of power. • In February 2017, Enbridge and Enbridge Energy Partners ﬁnalized the acquisition of a 27.6-percent interest in the 470,000-bpd Bakken Pipeline System, which will connect supply from the proliﬁc Bakken formation in North Dakota to eastern PADD II and U.S. Gulf Coast reﬁneries. In light of this acquisition, we announced the deferral of our Sandpiper Project in the Bakken region until such time as crude oil production in North Dakota recovers sufficiently to support development of additional new pipeline capacity. • Also in February, we announced the acquisition of an effective 50-percent stake in the 497-MW Hohe See Offshore Wind Project, which will be constructed Superior Total Shareholder Return1 During 2016, we took numerous steps to strengthen Enbridge’s balance sheet and improve overall ﬁnancial ﬂexibility. In total, we raised more than $10 billion in new long-term capital across the Enbridge group through public markets and our dividend reinvestment programs. In addition, as part of our asset-monetization program announced in association with the Spectra Energy combination, we sold approximately $1.7 billion of miscellaneous non-core assets and investments. Addressing challenges The year was not without its challenges and disappointments. Our primary focus is always on the safety of our people, communities and the environment. We responded quickly to the dangers posed by the extreme wildﬁres in and around Fort McMurray, Alberta, in May– ensuring the safety of our employees, working closely with our customers and temporarily shutting down 11.7% 12.0% 8.2% 14.5% 10.5% 4.7% 5 Year 10 Year Enbridge Inc. S&P/TSX Composite Index Peers (median) 1 Total shoreholder return inclusive of share price appreciation, assuming dividends are reinvested. or curtailing operations of some of our terminals and pipelines in the region. Overall in 2016, our rates of recordable and lost-days injuries were the lowest since we began tracking them. However, tragically, two contractors working on projects were fatally injured on the job. We take any safety incident very seriously, and we will apply the lessons learned from these incidents to our work practices. We were disappointed by the Canadian federal government’s decision in November to direct the National Energy Board to dismiss our Northern Gateway Project application and rescind its certiﬁcates. In May 2016, we began a strategic review of our U.S. sponsored-vehicle strategy in light of the commodity price environment that was particularly impacting the performance of Enbridge Energy Partners L.P.’s (EEP) and Midcoast Energy Partners L.P.’s (MEP) natural gas gathering and processing assets. In January 2017, we announced the privatization of MEP. We expect to complete a strategic review of EEP in the second quarter of 2017. Executive Leadership Team Al Monaco President & Chief Executive Officer Cynthia Hansen EVP, Utilities & Power Operations Guy Jarvis EVP & President, Liquids Pipelines Byron Neiles EVP, Corporate Services Karen Radford EVP & Chief Transformation Officer Bob Rooney EVP & Chief Legal Officer John Whelen EVP & Chief Financial Officer Bill Yardley EVP & President, Gas Transmission & Midstream Vern Yu EVP & Chief Development Officer 2016 Annual Report 7 Letter to Shareholders Repositioning for the future On September 6, 2016, we announced our combination with Spectra Energy– a combination that made great strategic and ﬁnancial sense at the time and even more so today as the outlook for energy and infrastructure development gains momentum in 2017. The combination brings together the best liquids, natural gas and natural gas liquids platforms. The infrastructure portfolio of the combined company is critical to meeting North America’s energy needs, driving economic growth and allowing North Americans to sustain our quality of life. We now have the largest energy infrastructure footprint in North America, with six strategic growth platforms – North American liquids pipelines; North American gas pipelines; Canadian midstream; U.S. midstream; utilities; and renewable power. Each has competitive positions and opportunities to grow organically, covering the best production basins and end-use markets, as well as the entire energy value chain–from storage, gathering and processing, to long-haul and natural gas distribution to consumers. Our liquids system is directly connected to more than 3.5 million bpd of reﬁning capacity and connected pipelines. We move approximately 20 percent of all natural gas consumed in the U.S. Our gas utilities serve 3.5 million residential, commercial and industrial customers. Taken together, this allows us to manage even larger-scale projects, offers greater cross-business value to our customers, gives us a strong position on which to grow, and provides us with a balance between liquids and natural gas. We also now have an industry-leading organic growth program. This includes $27 billion of secured growth projects expected to be in service through 2019, and an additional $48-billion pool of probability-weighted projects that are under development and will drive growth beyond 2019. With the closing of the transaction behind us, we’re focused on achieving synergies and moving forward as one company with one vision and one strategy. We’ve mapped out longer- term integration milestones, including harmonizing safety and operational procedures. We’ve also made very good progress in developing an execution plan to capture $540 million in pre-tax annual synergies by 2019. This includes work on organizational design, system optimizations and rationalizing our real-estate footprint, among other things. 8 Enbridge Inc. Our approach to the business won’t change While the size and reach of our company has changed, our approach to our businesses will remain the same. • We’ll keep our eyes on what matters most to us – the safety of the public and our people, operational reliability and protecting the environment. • We’ll continue to focus on improving our efficiency and enhancing our competitiveness so that we’re equipped to succeed in a new energy future–to be more effective, support our customers, win new business and improve how we get things done. • We’ll stay true to our value proposition for shareholders through our disciplined, low-risk business model. On the strength of our combined organic growth program, we’re conﬁdent we'll be able to extend our 10 –12 percent annual dividend growth through 2024. • Our discipline around capital investment isn't changing. We remain committed to maintaining Enbridge's strong balance sheet and credit ratings, and ample access to low-cost capital to fund our secured growth program. In fact, the combination with Spectra Energy is a Investing in Offshore Wind We see great potential in offshore wind and to date have invested in ﬁve large projects in the United Kingdom, France and Germany for a total of approximately 1,100 MW of net generation capacity under development. Offshore wind is one of the fastest-growing energy segments in Europe, where there is a signiﬁcant push for a greater component of renewables in the supply mix. This means these projects have very strong commercial underpinnings and secure, long-term revenue streams. Offshore wind is a strong ﬁt for Enbridge, given our history with onshore renewable technology, our major-projects capability and our experience in working offshore in the Gulf of Mexico. We plan to continue to grow our renewable generating capacity and be at the forefront of the global transition to a lower-carbon future. Al Monaco and Greg Ebel positive step change for this, creating signiﬁcant ﬁnancial ﬂexibility to continue to secure the most signiﬁcant and attractive growth projects. • We’ll continue to actively engage with all of our stakeholders, including those who oppose energy development – listening carefully, responding to concerns and acting on community input. This includes engagement with the Indigenous communities and Native American tribes located along our rights-of-way in Canada and the U.S. • For both Enbridge and Spectra Energy, developing our people has always been a priority and this too will remain the same. Our people are a critical part of Enbridge’s competitive advantage, and we’ll continue to develop our people at all levels of the organization and provide them with opportunities to grow and help us maintain our strong culture of success. Acknowledgements A bright future On behalf of the Board and the Executive Leadership Team, thank you to all of our employees for their hard work doing both their regular jobs and making the additional effort to see the combination with Spectra Energy through to fruition. We have a great team of people, and it’s your contribution that enables our success and makes Enbridge a great company. Thank you to the Board of Directors for their guidance through the combination process. David Arledge, James Blanchard and George Petty have retired from Enbridge’s Board and I thank all of them for their many years of service and guidance. Enbridge’s Board is now comprised of 13 Directors. We’re pleased to welcome Greg Ebel, formerly Chairman, President & CEO of Spectra Energy, as non-executive Chair of Enbridge’s Board, as well as incoming Board members Pamela Carter, Clarence Cazalot, Jr., Michael McShane and Michael Phelps. We’re extremely proud of what Enbridge has accomplished over the past seven decades, and our role in delivering energy and contribution to the economy. We’ve grown rapidly and expanded from our foundation in liquids pipelines into new platforms of natural gas and renewables. We’ve created value for our shareholders, generated economic opportunities and supported the communities in which we work. We’ve connected customers to the right markets and provided stable, competitive tolls so they can achieve the best netbacks. We’ve made safety our top priority and we continue to strengthen our safety performance and culture. This is our vision for Enbridge: delivering the energy people want and need; the ﬁrst choice of our customers and inspiring the trust of our stakeholders; a must-own investment for our shareholders; and at the core of it all, an energized and proud team. Al Monaco President & Chief Executive Officer March 13, 2017 2016 Annual Report 9 CSR Performance Highlights ee oo pp aa Corp ate ee oorr aa pp tt CC Re pons bility pp bb ooee yyiiii oo nnssppRReeRReRR RR tt iilliibb RReeRReRR Highligh s gggg ii ssgggg ii hhiillhhiiHH ll l 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, Indigenous 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 fueling people’s quality of life, because life takes energy. Systems and Detecting Leaks Systems and Detecting Leaks Systems and Detecting Leaks Systems and Detecting Leaks Systems and Detecting Leaks Systems and Detecting Leaks Systems and Detecting Leaks Systems and Detecting Leaks Systems and Detecting Leaks Our goal is to achieve industry leadership in the safety and reliability of our pipelines and facilities, and protection of the environment. 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Our commitment is based on caring for our employees, contractors, customers, communities and the environment. 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While our recordable injuries and lost-days injuries in 2016 were the lowest they have been since we began tracking them, tragically two members of our team – contractors working on projects on our behalf – were fatally injured on the job in separate incidents. 1/1 0/0 0/2 Fatal Incidents Employees/ Contractors 8 Number of Liquids Spills 0.11 0.12 Lost-Days Injuries per 200,000 employee hours worked 0.05 14 10 2,522 Our 2016 CSR & Sustainability Report is available at csr.enbridge.com 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance 2016 at a Glance Maintaining the Fitness of our Systems and Detecting Leaks $750$750 $750M $750$750 $750$750$750$750MM We invested about $750 million in programs that help us maintain the ﬁtness of our systems and detect leaks across our operations in Canada and the U.S. 15,681 15,681 15,681 15,681 15,681 15,681 15,681 15,681 15,681 15,681 15,681 pipeline inspections conducted on our liquids and natural gas pipelines and distribution network 99.99% 99.99% 99.99% 99.99% 99.99% 99.99% 99.99% 99.99% 99.99% There were eight reportable spills on our liquids pipelines systems in Canada and the U.S., compared with 14 in 20151.The volume from these spills was 657 barrels, compared with 480 barrels in 2015. These amounts represent a reliable delivery rate of 99.99 percent for the year, based on our volumes spilled and gross delivery volumes. Renewable & Alternative Energy BB>$5>$5BB>$5>$5 >$5B >$5>$5 >$5>$5BB>$5>$5 invested in renewable and alternative energy projects since 2002 ~3,500 ~3,500MW2 ~3,500 ~3,500 22MWMWMWMW ~3,500 ~3,500 ~3,500 ~3,500 ~3,500 of gross generating capacity operating, secured or under construction (Enbridge Inc. and subsidiaries’ interests: ~2,500 MW) 0.94 0.66 0.55 Recordable Injuries per 200,000 employee hours worked 480 2015 657 2016 2014 Volume of Liquids Spills (Barrels) 1 We have restated the values for our 2014 and 2015 number and volume of liquids spills such that they align with our Project, in which Enbridge acquired an effective 50-percent deﬁnition for Reportable Incidents. Please see Enbridge’s 2016 CSR & Sustainability Report for more information. interest in February 2017. 10 Enbridge Inc. 2014 2015 2016 2 Includes 497 gross MW from the Hohe See Offshore Wind Corporate Governance 2016 Annual Report 11 Committed to Strong Governance At Enbridge, corporate governance means ensuring a comprehensive system of stewardship and accountability is in place and functioning among Directors, management and employees. As a result of the combination with Spectra Energy in 2017, we have redeﬁned Enbridge’s Board of Directors and executive leadership team to combine the two strong leadership teams and to bring experience and expertise from both companies. However, our overall commitment to a strong corporate governance culture stays the same: We are committed to the principles of good governance, and the Company employs a variety of policies, programs and practices to manage corporate governance and ensure compliance. Board of Directors As of February 27, 2017 (pictured, left to right) J. Herb England Catherine L. Williams Gregory L. Ebel, Chair Marcel R. Coutu V. Maureen Kempston Darkes Al Monaco Rebecca B. Roberts Dan C. Tutcher Michael McShane Michael E.J. Phelps Pamela L. Carter Charles W. Fischer Clarence P. Cazalot, Jr. Enbridge Inc. Financial Report Management’s Discussion & Analysis 46 Other Announced Projects Under Development 14 Overview 15 Merger Agreement with Spectra Energy 16 16 17 18 United States Sponsored Vehicle Strategy Canadian Restructuring Plan The Fund Group 2014 Drop Down Transaction Performance Overview 26 Non-GAAP Measures 30 Corporate Vision and Strategy 33 Industry Fundamentals 37 Growth Projects—Commercially Secured Projects 40 Liquids Pipelines 43 Gas Distribution 44 Gas Pipelines and Processing 46 Green Power and Transmission 49 Liquids Pipelines 65 Gas Distribution 70 Gas Pipelines and Processing 80 Green Power and Transmission 82 84 85 Energy Services Eliminations and Other Liquidity and Capital Resources 94 Outstanding Share Data 95 Quarterly Financial Information 96 97 Related Party Transactions Risk Management and Financial Instruments 103 Critical Accounting Estimates 105 Changes In Accounting Policies 107 Controls and Procedures 12 Enbridge Inc. 2016 Annual Report Consolidated Financial Statements 141 15. Goodwill 108 Management’s Report 109 Independent Auditor’s Report 111 Consolidated Statements of Earnings 112 Consolidated Statements of Comprehensive Income 113 Consolidated Statements of Changes in Equity 114 Consolidated Statements of Cash Flows 115 Consolidated Statements of Financial Position Notes to the Consolidated Financial Statements 116 1. General Business Description 116 2. Summary of Signiﬁcant Accounting Policies 123 3. Changes in Accounting Policies 125 4. Segmented Information 128 5. Financial Statement Effects of Rate Regulation 130 6. Acquisition and Dispositions 133 7. Accounts Receivable and Other 133 8. Inventory 134 9. Property, Plant and Equipment 135 10. Variable Interest Entities 138 11. Long-Term Investments 140 12. Restricted Long-Term Investments 141 141 13. Deferred Amounts and Other Assets 14. Intangible Assets 142 16. Accounts Payable and Other 143 17. Debt 145 18. Other Long-Term Liabilities 145 19. Asset Retirement Obligations 145 20. Noncontrolling Interests 148 21. Share Capital 151 22. Stock Option and Stock Unit Plans 154 23. Components of Accumulated Other Comprehensive Income/(Loss) 156 24. Risk Management and Financial Instruments 166 25. Income Taxes 168 26. Retirement and Postretirement Beneﬁts 173 27. Other Income/(Expense) 173 28. Severance Costs 173 29. Changes in Operating Assets and Liabilities 174 30. Related Party Transactions 174 31. Commitments and Contingencies 176 32. Guarantees 177 33. Subsequent Events 178 Glossary 180 Three-Year Consolidated Highlights 182 Investor Information 13 Management’s Discussion & Analysis This Management’s Discussion and Analysis (MD&A) dated February 17, 2017 should be read in conjunction with the audited consolidated ﬁnancial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) for the year ended December 31, 2016, prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). All ﬁnancial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com. Effective January 1, 2016, Enbridge revised its reportable segments to better reﬂect the underlying operations of the Company. The Company believes this new format more clearly describes the ﬁnancial performance of its business segments, provides increased transparency with respect to operational results and aligns with business segment decision making and management. On May 12, 2016, the Company ﬁled an amended MD&A for the year ended December 31, 2015 to retrospectively apply the revisions to its reportable segments to the 2015 annual MD&A of the Company that was previously ﬁled on February 19, 2016. Revisions to the segmented information presentation included: • The replacement of the previous segments: Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services; Sponsored Investments; and Corporate with new segments: Liquids Pipelines; Gas Distribution; Gas Pipelines and Processing; Green Power and Transmission; and Energy Services; and • Presenting the Earnings before interest and income taxes (EBIT) of each segment as opposed to Earnings attributable to Enbridge common shareholders. Amounts related to Interest expense, Income taxes, Earnings attributable to noncontrolling interests and redeemable noncontrolling interests and Preference share dividends are now reported on a consolidated basis. These changes had no impact on reported consolidated earnings for the years ended December 31, 2015 and 2014. Overview Enbridge, a Canadian company, is a North American leader in delivering energy. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids transportation system. The Company also has signiﬁcant and growing involvement in natural gas gathering, transmission and midstream businesses. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company and provides distribution services in Ontario, Quebec, New Brunswick and New York State. As a generator of energy, Enbridge has interests in approximately 3,500 megawatts (MW) (2,500 MW net) of renewable and alternative energy generating capacity which is operating, secured or under construction, and the Company continues to expand its interests in wind, solar and geothermal power. Enbridge employs approximately 9,200 people, primarily in Canada and the United States. The Company’s activities are carried out through ﬁve business segments: Liquids Pipelines; Gas Distribution; Gas Pipelines and Processing; Green Power and Transmission; and Energy Services, as discussed below. Liquids Pipelines Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and reﬁned products pipelines and terminals in Canada and the United States, including Canadian Mainline, Lakehead Pipeline System (Lakehead System), Regional Oil Sands System, Mid-Continent and Gulf Coast, Southern Lights Pipeline, Bakken System and Feeder Pipelines and Other. 14 Enbridge Inc. 2016 Annual Report Total Assets (millions of Canadian dollars) 2 3 8 5 8 , 2 1 5 4 8 , 1 4 7 2 7 , 14 15 161 ■ Liquids Pipelines ■■■■■ ■ Liquids Pipelines ■■ ■ Gas Distribution Gas Distribution ■ Gas Pipelines and Processing ■ Gas Pipelines and Processing ■ ■ Green Power and Transmission Green Power and Transmission ■ Energy Services ■ Energy Services ■ Elimination and Other ■ Elimination and Other 1 Effective January 1, 2016, the Company revised its reportable segments and reported Earnings before interest and income taxes for each reporting segment. The above information has reﬂected this change. Gas Distribution Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD), which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick and the Company’s investment in Noverco Inc. (Noverco). Gas Pipelines and Processing Gas Pipelines and Processing consists of investments in natural gas pipelines and gathering and processing facilities. Investments in natural gas pipelines include the Company’s interests in Alliance Pipeline, Vector Pipeline (Vector) and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing The combination will create the largest energy infrastructure company in North America and one of the largest globally based on a pro-forma enterprise value of approximately $165 billion (US$127 billion) as measured at the time of the announcement. The new company would have a substantial capital project portfolio, including $26 billion of commercially secured growth projects through 2019 and a $48 billion probability risk-weighted development project portfolio through 2024. Upon closing of the Merger Transaction, the Company expects to further increase its quarterly common share dividend to approximately 15% above the prevailing quarterly rate of $0.530 per common share in 2016. Also, post closing of the Merger Transaction, the combined capital growth program is expected to deliver ongoing dividend growth of 10%-12% per annum through 2024, while maintaining a payout of 50% to 60% of available cash ﬂow from operations (ACFFO). include the Company’s interest in Aux Sable, a natural gas extraction Under the terms of the Merger Transaction, Spectra Energy and fractionation business located near the terminus of the Alliance shareholders will receive 0.984 shares of the combined company Pipeline, Canadian Midstream assets located in northeast British for each share of Spectra Energy common stock they own. Upon Columbia and northwest Alberta and United States Midstream completion of the Merger Transaction, Enbridge shareholders are assets located primarily in Texas and Oklahoma. expected to own approximately 57% of the combined company and Green Power and Transmission Green Power and Transmission consists of the Company’s investments in renewable energy assets and transmission facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United States primarily in Colorado, Texas, Indiana and West Virginia. The Company also has assets under development located in Europe. Energy Services The Energy Services businesses in Canada and the United States undertake physical commodity marketing activity and logistical services, oversee reﬁnery supply services and manage the Company’s volume commitments on various pipeline systems. Eliminations and Other In addition to the segments noted above, Eliminations and Other includes operating and administrative costs and foreign exchange Spectra Energy shareholders are expected to own approximately 43%. The combined company will be called Enbridge Inc. The Merger Transaction was unanimously approved by the Boards of Directors of both companies. Shareholders’ approval for both companies was received in December 2016 and both companies continue to work to meet closing conditions, and the required regulatory applications are progressing. Clearance has been received from the Canadian Transportation Agency, the Committee on Foreign Investment in the United States and the United States Federal Trade Commission to complete the Merger Transaction. Additionally, the Ontario Energy Board has communicated that it is satisﬁed the Merger Transaction does not require its approval. As a standard part of the regulatory approval process for transactions of this type, both companies continue to work closely with the Canadian Competition Bureau to expeditiously conclude its review of the Merger Transaction. Subject to this review and other customary conditions, the Merger Transaction is expected to close in the ﬁrst quarter of 2017. costs which are not allocated to business segments. Also included Assets Monetization Plan in Eliminations and Other are new business development activities, general corporate investments and elimination of transactions between segments required to present ﬁnancial performance and ﬁnancial position on a consolidated basis. Merger Agreement with Spectra Energy On September 6, 2016 Enbridge and Spectra Energy Corp (Spectra Energy) announced that they had entered into a deﬁnitive merger agreement under which Enbridge and Spectra Energy would combine in a stock-for-stock merger transaction (the Merger Transaction), which valued Spectra Energy common stock at approximately $37 billion (US$28 billion), based on the closing price of Enbridge’s common shares on September 2, 2016. The ﬁnal purchase price for the Merger Transaction may vary based on the market price of Enbridge’s common shares at the time the Merger Transaction is completed. There is no assurance when or if the Merger Transaction will be completed. Concurrent with the announcement of the Merger Transaction, the Company stated its intention to divest approximately $2 billion of assets over a twelve-month period to provide for additional ﬁnancial ﬂexibility. On December 1, 2016, Enbridge Income Partners LP (EIPLP) completed the sale of the South Prairie Region assets to an unrelated party for cash proceeds of $1.08 billion. The proceeds from the sale will be reinvested in the secured growth capital programs of Enbridge Pipelines (Athabasca) Inc. (EPAI), including the Regional Oil Sands Optimization Project and Norlite Pipeline System (Norlite) project. For further details on the South Prairie Region assets that were sold, refer to Liquids Pipelines – Feeder Pipelines and Other. Also, during the fourth quarter of 2016, the Company entered into agreements to sell approximately $0.6 billion of additional miscellaneous non-core assets and investments, the full proceeds of which Enbridge expects will be realized before the end of the ﬁrst quarter of 2017. Management’s Discussion & Analysis 15 United States Sponsored Vehicle Strategy On May 2, 2016, EEP announced that it was evaluating opportunities to strengthen its business in light of the commodity price environment which was particularly impacting the performance of its natural gas gathering and processing assets. As part of this evaluation, EEP was exploring various strategic alternatives for its investments in Midcoast Operating Partners, L.P. and Midcoast Energy Partners, L.P. (MEP). dividend increase effective March 1, 2016. The Transaction provided Enbridge with an alternate source of funding for its enterprise wide growth initiatives and enhanced its competitiveness for new organic growth opportunities and asset acquisitions. In conjunction with the execution of the Transaction, Enbridge adopted a supplemental cash ﬂow metric, ACFFO, which was introduced in the second quarter of 2015 and continues to be a part of the Company’s normal course annual and quarterly reporting of ﬁnancial performance. ACFFO is used to assess the performance of the Company’s base business and the impact of its growth On January 27, 2017, Enbridge announced that it had entered into program. The Company also started expressing its dividend payout a merger agreement through a wholly-owned subsidiary, whereby it range as a percentage of ACFFO rather than adjusted earnings will take private MEP by acquiring all of the outstanding publicly-held and established a long-term target dividend payout of 40% to 50% common units of MEP. Total consideration to be paid by Enbridge for of ACFFO. For impacts on the Company’s long-term target payout these units will be approximately US$170 million and the transaction policy that would result from the Merger Transaction, see Merger is expected to close in the second quarter of 2017. Agreement with Spectra Energy above. In addition, as part of the on-going strategic review of EEP, Consideration further joint funding actions with EEP were announced. Speciﬁcally, Enbridge and EEP entered into an agreement for the joint funding of the United States portion of the Line 3 Replacement Program (U.S. L3R Program), whereby Enbridge and EEP will fund 99% and 1%, respectively, of the project development and construction cost. Enbridge has reimbursed EEP approximately US$450 million for capital expenditures incurred to date on the project and will fund 99% of the expenditures through construction. For additional information on the U.S. L3R Program, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Line 3 Replacement Program – United States Line 3 Replacement Program (EEP). EEP will retain an option to acquire up to 40% of U.S. L3R Program at book value, once the project is completed and in service. 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 EEP also used a portion of the proceeds reimbursed by Enbridge after issuance). under the U.S. L3R Program joint funding agreement to acquire an additional 15% interest in the cash generating Eastern Access Project pursuant to an existing joint funding agreement for approximately US$360 million. The strategic review of EEP is ongoing and it is currently expected that any resulting actions will be announced early in the second quarter of 2017. Enbridge will continue working closely with EEP on the strategic review, but any of these anticipated actions are not expected to be material to Enbridge’s projections. Canadian Restructuring Plan On September 1, 2015, Enbridge completed the transfer of its Canadian Liquids Pipelines business, held through Enbridge Pipelines Inc. (EPI) and EPAI, and certain Canadian renewable energy assets to the Fund Group (comprising Enbridge Income Fund (the Fund), Enbridge Commercial Trust (ECT), EIPLP and the subsidiaries and investees of EIPLP) for aggregate consideration of $30.4 billion plus incentive distribution and performance rights (the Canadian Restructuring Plan or the Transaction). Enbridge will continue to earn a base incentive fee from the Fund Group through management and incentive fees and Incentive Distribution Rights (IDR), which entitle it to receive 25% of the pre-incentive distributable cash ﬂow above a base distribution threshold of $1.295 per unit, adjusted for a tax factor. The base incentive fee is paid out of ECT. Distributions over $1.890 per unit will be paid out of EIPLP. In addition, Enbridge received the TPDR, a distribution equivalent to 33% of pre-incentive distributable cash ﬂow above the base distribution of $1.295 per unit. The TPDR are paid in the form of Class D units of EIPLP and will be issued each month until the later of the end of 2020 or 12 months after the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program) enters service. The Class D unitholders receive a distribution each month equal to the per unit amount paid on Class C units of EIPLP, but to be paid in kind in additional Class D units. Each Class D unit is convertible into a cash paying Class C unit of EIPLP in the fourth year after its issuance. The ordinary trust units of the Fund (Fund Units), Class A units of EIPLP and the EIPLP Class C units will pay a per unit cash The Transaction was a key component of Enbridge’s Financial distribution equivalent to the per unit cash distribution that the Fund Optimization Strategy introduced in December 2014, which included pays on its units held by Enbridge Income Fund Holdings Inc. (ENF). an increase in the Company’s targeted dividend payout. It advanced The Fund Units, EIPLP’s Class C units and existing preferred the Company’s sponsored vehicle strategy and supported Enbridge’s units of ECT also include an exchange right whereby they may 33% dividend increase effective March 1, 2015 and a further 14% be converted into common shares of ENF on a one-for-one basis. 16 Enbridge Inc. 2016 Annual Report Financing Plan Fund Governance To acquire an increasing ownership interest in the Fund Group, ENF’s Enbridge continues to act as the manager of the Fund Group ﬁnancing plan contemplates the issuance by ENF of $600 million and operator and commercial developer of the Canadian Liquids to $800 million of public equity per year in one or more tranches Pipelines business. This will ensure continuity of management through 2018 to fund an increasing investment in the Canadian Liquids and operational expertise, with an ongoing commitment to the safe Pipelines business. Enbridge has agreed to backstop the equity and reliable operation of the system. As a result of its signiﬁcant funding required by ENF to undertake the growth program embedded ownership interest, Enbridge has the right to appoint a majority in the assets it acquired in the Transaction. The amount of public of the Trustees of the Board of ECT for as long as the Company equity issued by ENF will be adjusted as necessary to match its holds a majority economic interest in the Fund Group. A standing capacity to raise equity funding on favourable terms. In November 2015, conﬂicts committee has been established to review certain material ENF successfully completed an equity offering of 21.5 million transactions and arrangements where the interests of Enbridge, common shares at a price of $32.60 per share for gross proceeds or its affiliates, and the relevant entity in the Fund Group, or its of $700 million. Concurrent with the closing of the equity offering, affiliates, come into conﬂict. 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. On April 20, 2016, ENF completed a public equity offering of 20.4 million common shares at a price of $28.25 per share for gross proceeds of $575 million. Concurrent with the closing of the equity offering, Enbridge subscribed for 5.1 million common shares at a price of $28.25 per share, for total proceeds of $143 million, on a private placement basis to maintain its 19.9% ownership interest in ENF. ENF used the proceeds from the sale of the common shares to subscribe for additional Fund Units at the price of $28.25 per share. The proceeds from the issuance of the Fund Units are being used to fund the secured growth capital programs of EPAI and EPI. On December 1, 2016, EIPLP completed the sale of the Southern Prairie Region assets for total consideration of $1.08 billion. The proceeds will be used to reduce leverage, fund the Fund Group’s secured growth program and displace planned equity issuances in 2017. Development Opportunities The Canadian Liquids Pipelines business is expected to have future organic growth opportunities beyond the current inventory of secured projects. The Fund Group has a ﬁrst right to execute any such projects that fall within the footprint of the Canadian Liquids Pipelines business. Should the Fund Group choose not to proceed with a speciﬁc growth opportunity, Enbridge may pursue such opportunity. Economic Interest Upon closing of the Transaction, Enbridge’s overall economic The Fund Group 2014 Drop Down Transaction In November 2014, the Fund Group completed the acquisition of Enbridge’s 50% interest in the United States portion of Alliance Pipeline (Alliance Pipeline US) and the subscription for and purchase of Class A units of certain Enbridge subsidiaries that indirectly own the Canadian and United States segments of Southern Lights Pipeline (Southern Lights Class A units). The Southern Lights Class A units, which are non-voting and do not confer any governance or ownership rights in Southern Lights Pipeline, provide a deﬁned cash ﬂow stream to the Fund Group. Total consideration for the transaction was approximately $1.8 billion. Enbridge received on closing approximately $421 million in cash and $461 million in the form of preferred units of ECT, an entity within the Fund Group. Under the agreement, Enbridge provided bridge debt ﬁnancing to the Fund Group in the form of an $878 million long-term note payable by the Fund Group and bearing interest of 5.5% per annum. In November 2014, the Fund Group issued $1,080 million of medium- term notes with a portion of these proceeds used to fully repay the bridge debt ﬁnancing to Enbridge. The Fund Group also issued $421 million of trust units to ENF to fund the cash component of the consideration. Enbridge applied approximately $84 million of cash to acquire additional common shares of ENF, thereby maintaining its 19.9% interest in ENF. At the time of the transaction, the Fund Group previously owned a 50% investment in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada). The asset transfers described above occurred between entities under common control of Enbridge, and the intercompany gains interest in the Fund Group, including all of its direct and indirect realized by the selling entities in the year ended December 31, 2014 interests in the Fund Group, was 91.9%. Upon completion of have been eliminated from the Consolidated Financial Statements the $700 million common share issuance in November 2015 of Enbridge. However, as these transactions involved the sale and $575 million common share issuance in April 2016 discussed of shares and partnership units, all tax consequences have above, Enbridge’s economic interest, through its ownership remained in consolidated earnings and resulted in a charge of ENF, decreased to 89.2% and 86.9%, respectively. As at of $157 million in 2014. December 31, 2016, Enbridge’s total economic interest in the Fund Group remained at 86.9%. As ENF executes on its ﬁnancing plan and increases its ownership in the Fund Group over time, Enbridge’s economic interest is expected to decline over time. 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. Management’s Discussion & Analysis 17 Performance Overview (millions of Canadian dollars, except per share amounts) Earnings attributable to common shareholders Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other Earnings before interest and income taxes Interest expense Income taxes recovery/(expense) (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests Preference share dividends Earnings/(loss) attributable to common shareholders Discontinued operations – Gas Pipelines and Processing Earnings/(loss) per common share Diluted earnings/(loss) per common share Adjusted earnings Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other Interest expense2 Income taxes2 Noncontrolling interests and redeemable noncontrolling interests2 Discontinued operations Preference share dividends Adjusted earnings1 Adjusted earnings per common share1 Cash ﬂow data Cash provided by operating activities Cash provided by/(used) in investing activities Cash provided by ﬁnancing activities Available cash ﬂow from operations3 Available cash ﬂow from operations Dividends Common share dividends declared Dividends paid per common share Revenues Commodity sales Gas distribution sales Transportation and other services Total assets Total long-term liabilities Three months ended December 31, Year ended December 31, 2016 2015 2016 2015 2014 1,389 150 24 30 (147) (219) 1,227 (412) 32 (406) (76) 365 – 365 0.39 0.39 1,011 150 95 43 (5) (96) 675 111 69 50 92 (156) 841 (371) (94) 76 (74) 378 – 378 0.44 0.44 949 128 88 49 (22) (74) (403) (136) (61) – (76) 522 0.56 1,058 8 1 (372) (130) (48) – (74) 494 0.58 772 (2,262) 1,457 3,557 1,806 1,980 492 171 154 (185) (148) 4,041 (1,590) (142) (240) (293) 1,776 – 1,776 1.95 1.93 455 (229) 177 325 (899) 1,635 (1,624) (170) 410 (288) (37) – (37) (0.04) (0.04) 432 467 149 730 (456) 3,302 (1,129) (611) (203) (251) 1,108 46 1,154 1.39 1.37 3,958 3,384 2,592 494 366 165 28 (349) 4,662 (1,545) (520) (226) – (293) 2,078 2.28 5,211 (5,192) 1,102 446 336 175 61 (246) 4,156 (1,273) (486) (243) – (288) 1,866 2.20 4,571 (7,933) 2,973 391 293 151 42 (60) 3,409 (926) (434) (225) 1 (251) 1,574 1.90 2,547 (11,891) 9,770 879 876 3,713 3,154 2,506 497 0.530 6,436 703 2,199 9,338 85,832 47,511 401 0.465 6,074 672 2,168 8,914 84,515 51,362 1,945 2.12 22,816 2,486 9,258 34,560 85,832 47,511 1,596 1.86 23,842 3,096 6,856 33,794 84,515 51,362 1,177 1.40 28,281 2,853 6,507 37,641 72,741 42,190 Adjusted earnings before interest and income taxes1 1,198 1,118 1 Adjusted EBIT, adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures see page 26. 2 These balances are presented net of adjusting items. 3 ACFFO is deﬁned as cash ﬂow provided by operating activities before changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. ACFFO is a non-GAAP measure that does not have any standardized meaning prescribed by GAAP – see Non-GAAP Measures. 18 Enbridge Inc. 2016 Annual Report • In September 2016, EEP announced that it had applied for the withdrawal of the regulatory applications for the Sandpiper Project that were pending with the Minnesota Public Utilities Commission (MNPUC). In connection with this announcement and other factors, the total impairment charge in respect of the Sandpiper Project recorded during the year, including related project costs of $12 million, was $1,004 million, of which $875 million was attributable to noncontrolling interests in EEP and Marathon Petroleum Corporation (MPC), EEP’s partner in the Sandpiper Project ($81 million after-tax in total attributable to Enbridge’s common shareholders). • In the second quarter of 2016, an impairment charge of $176 million ($103 million after-tax attributable to Enbridge) was recorded relating to Enbridge’s 75% joint venture interest in Eddystone Rail, a rail-to-barge transloading facility located in the greater Philadelphia, Pennsylvania area that delivers Bakken and other light sweet crude oil to Philadelphia area reﬁneries. Due to a signiﬁcant decrease in price spreads between Bakken crude oil and West Africa/Brent crude oil and increased competition in the region, demand for Eddystone Rail services dropped signiﬁcantly, resulting in an impairment of this facility. • EBIT for 2015 was also impacted by a goodwill impairment charge of $440 million ($167 million after-tax attributable to Enbridge) recognized in the second quarter of 2015 related to EEP’s natural gas and NGL businesses. The prolonged decline in commodity prices reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL pipelines and processing systems, which EEP holds directly and indirectly through its partially-owned subsidiary, MEP. EBIT and Earnings/(Loss) Attributable to Common Shareholders EBIT For the year ended December 31, 2016, EBIT was $4,041 million compared with $1,635 million for the year ended December 31, 2015 and $3,302 million for the year ended December 31, 2014. For the fourth quarter of 2016, EBIT was $1,227 million compared with $841 million for the fourth quarter of 2015. As discussed below in Adjusted EBIT, the Company has continued to deliver strong earnings growth from a majority of its businesses over the course of the last two years, offset partly in the second quarter of 2016 by the impacts of extreme wildﬁres in northeastern Alberta discussed in Liquids Pipelines – Impact of Wildﬁres in Northeastern Alberta. The positive impact of this growth and the comparability of the Company’s earnings for each period are impacted by a number of unusual, non-recurring or non-operating factors that are enumerated in the Non-GAAP Reconciliation tables and discussed in the results for each reporting segment, the most signiﬁcant of which are summarized below: • The Company has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks which create volatility in short-term earnings. Over the long term, Enbridge believes its hedging program supports the reliable cash ﬂows and dividend growth upon which the Company’s investor value proposition is based. For the year ended December 31, 2016, the Company’s EBIT reﬂected $543 million of unrealized derivative fair value gains, compared with $2,017 million and $36 million of unrealized derivative fair value loss in the corresponding 2015 and 2014 periods. • EBIT for 2016 reﬂected an $850 million gain ($520 million after-tax attributable to Enbridge) within the Liquids Pipelines segment related to the disposition of the South Prairie Region assets in December 2016. • The Company’s 2016 EBIT was also impacted by certain impairment charges reﬂected within the Liquids Pipelines segment. In the fourth quarter of 2016, the Canadian Federal Government directed the National Energy Board (NEB) to dismiss the Company’s Northern Gateway Project (Northern Gateway) application and the Certiﬁcates of Public Convenience and Necessity under the authority of the NEB (the Certiﬁcates) have been rescinded. In consultation with potential shippers and Aboriginal equity partners, the Company assessed this decision and concluded that the project cannot proceed as envisioned. After taking into consideration the amount recoverable from potential shippers on Northern Gateway, the Company reﬂected an impairment of $373 million ($272 million after-tax) in the fourth quarter of 2016. Management’s Discussion & Analysis 19 Earnings/(Loss) Attributable to Common Shareholders For the year ended December 31, 2016, earnings attributable to common shareholders were $1,776 million ($1.95 earnings per common share) compared with a loss of $37 million ($0.04 loss per common share) for the year ended December 31, 2015 and earnings of $1,154 million ($1.39 earnings per common share) for the year ended December 31, 2014. For the quarter ended December 31, 2016, earnings attributable to common shareholders were $365 million ($0.39 earnings per common share) compared with $378 million ($0.44 earnings per common share) for the quarter ended December 31, 2015. In addition to the factors discussed in EBIT above and in Adjusted EBIT and Adjusted Earnings below, the year-over-year and fourth quarter-over-quarter comparability of earnings/(loss) attributable to common shareholders was impacted by a number of unusual, non-recurring and non-operating factors that are summarized and described under Non-GAAP Reconciliation – EBIT to Adjusted Earnings. Adjusted EBIT For the year ended December 31, 2016, adjusted EBIT was $4,662 million, compared with adjusted EBIT of $4,156 million for the year ended December 31, 2015. For the fourth quarter ended December 31, 2016, adjusted EBIT was $1,198 million, an increase of $80 million over the corresponding 2015 period. Growth in consolidated adjusted EBIT year-over-year was largely driven by stronger contributions from the Company’s Liquids Pipelines segment which beneﬁtted from a number of new assets that were placed into service in 2015, Earnings/(Loss) Attributable to Common Shareholders (millions of Canadian dollars) 5 5 5 , 1 1 2 3 , 1 0 3 9 1 0 8 0 0 7 6 7 7 , 1 4 5 ,1 1 2 0 6 6 4 4 ) 7 3 ( 072 082 092 101 111 121 131 141 151 161 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. the most prominent being the expansion of the Company’s mainline system in the third quarter of 2015, as well as the reversal and expansion of Line 9B and completion of the Southern Access Extension in the fourth quarter of 2015, which provided increased access to the eastern Canada and Patoka markets, respectively. The Company continued to realize throughput growth on the Canadian Mainline, Lakehead System and Regional Oil Sands System primarily due to strong oil sands production growth in western Canada enabled by recently completed pipeline expansion projects. However, the positive effect of increased production and higher capacity on liquids pipelines throughput was partially negated in the second quarter of 2016 by the impact of extreme wildﬁres in northeastern Alberta which led to a temporary shutdown of certain of the Company’s upstream pipelines and terminal facilities resulting in a disruption of service on Enbridge’s Regional Oil Sands System with corresponding impacts into and out of Enbridge’s downstream pipelines, including Canadian Mainline and the Lakehead System. Reduced system deliveries resulted in a negative impact of approximately $74 million on the Company’s adjusted EBIT for 2016. Growth in Canadian Mainline adjusted EBIT was also partially offset by a combination of a lower average International Joint Tariff (IJT) Residual Benchmark Toll, which decreased effective April 1, 2016, and a lower foreign exchange rate on hedges used to convert Canadian Mainline United States dollar toll revenues to Canadian dollars. In 2016, the Company also beneﬁtted from stronger adjusted EBIT contributions from the United States Mid-Continent and Gulf Coast systems, attributable to increased transportation revenues mainly resulting from an increase in the level of committed take-or-pay volumes on the Flanagan South Pipeline (Flanagan South). Adjusted EBIT from Feeder Pipelines and Other was also higher, reﬂecting the beneﬁts of a full year of earnings from Southern Access Extension. These positive trends on consolidated adjusted EBIT were partially offset by the performance of the United States portion of the Bakken System where adjusted EBIT fell primarily due to a lower surcharge on tolls subject to annual adjustment, as well as lower revenues from EEP’s Berthold rail facility as a result of declining volumes on expiry of contracts. 20 Enbridge Inc. 2016 Annual Report Many of the annual trends discussed above were also factors driving which also resulted in a lower adjusted loss before interest adjusted EBIT growth in the Liquids Pipelines segment in the fourth and income taxes for the fourth quarter of 2016 compared with quarter of 2016, when compared with the fourth quarter of 2015. the corresponding 2015 period. However, the decrease in Canadian Mainline IJT Residual Benchmark Toll and a lower rate on foreign exchange hedges of United States dollar toll revenue resulted in a decrease in Canadian Mainline adjusted EBIT for the fourth quarter of 2016 compared with the fourth quarter of 2015. In addition, there was a decrease in Mid-Continent and Gulf Coast adjusted EBIT for the fourth quarter of 2016 compared with the corresponding 2015 period, due to a year-over- year decline in demand for services on Spearhead Pipeline. Within Eliminations and Other, a higher realized foreign exchange derivative loss related to settlements under the Company’s foreign exchange risk management program, as well as higher operating and administrative expenses resulted in an increase in year-over-year adjusted loss before interest and income taxes. The realized loss in Eliminations and Other serves to partially offset the positive effect of translating the earnings performance of the United States dollar denominated businesses to Canadian dollars at the prevailing Within the Gas Distribution segment, EGD, which operates under exchange rate, which averaged $1.32 in 2016, and which is a ﬁve-year customized Incentive Rate Plan approved in 2014, reﬂected in the reported EBIT of the applicable business segments. generated higher adjusted EBIT in 2016 primarily due to higher Operating and administrative expenses, which were higher primarily distribution charges arising from growth in EGD’s rate base. due to an increase in depreciation expense, resulting from investment The Gas Pipelines and Processing segment beneﬁtted from operational efficiencies achieved by Alliance Pipeline. The Enbridge Offshore Pipelines’ (Offshore) Heidelberg Oil Pipeline (Heidelberg Pipeline) which was placed into service in January 2016 and in new information technology assets, and lower recoveries from other business segments, also contributed to a higher fourth quarter adjusted loss before interest and income taxes, when compared with the corresponding 2015 period. Canadian Midstream’s Tupper Main and Tupper West gas plants For the year ended December 31, 2015, adjusted EBIT was (the Tupper Plants) which were acquired on April 1, 2016 also $4,156 million, compared with adjusted EBIT of $3,409 million contributed to the year-over-year increase in the Gas Pipelines for the year ended December 31, 2014. The year-over-year growth and Processing segment’s adjusted EBIT. The positive effects were in consolidated adjusted EBIT was largely driven by stronger partially offset by the impact of lower volumes on US Midstream contributions from the Liquids Pipelines segment. The Canadian facilities due to reduced drilling by producers. Mainline contribution increased primarily from higher throughput The Green Power and Transmission segment adjusted EBIT decreased year-over-year as a result of disruptions at certain eastern Canadian wind farms in the ﬁrst quarter and fourth quarter of 2016 due to weather conditions which caused icing of blades, as well as weaker wind resources experienced at certain facilities in Canada during the ﬁrst half and fourth quarter of 2016. These negative effects were partially offset by stronger wind resources at the Company’s United States wind farms during the second half of 2016. that resulted from strong oil sands production in western Canada combined with strong downstream reﬁnery demand, as well as ongoing efforts by the Company to optimize capacity utilization and to enhance scheduling efficiency with shippers. These positive factors were partially offset by a lower year-over-year average Canadian Mainline IJT Residual Benchmark Toll. The Lakehead System also experienced year-over-year growth in adjusted EBIT, mainly due to higher throughput and tolls, as well as contributions from new assets placed into service in 2014 and 2015, the most Within the Energy Services segment, a decrease in adjusted EBIT prominent being the expansion of the Company’s mainline system in 2016 reﬂected weaker performance from Energy Services’ completed in July 2015 and the replacement and expansion Canadian and United States operations during the ﬁrst half of 2016. of Line 6B completed in 2014. In 2015, the Company also beneﬁtted The compression of certain crude oil location and quality differentials from a full-year of EBIT contributions from Mid-Continent and and the impact of a weaker NGL market drove a year-over-year Gulf Coast, mainly attributed to the Flanagan South and Seaway decrease in adjusted EBIT. This decrease was partially offset by Twin pipelines, both of which commenced service in late 2014. positive contributions from increased crude oil storage opportunities Management’s Discussion & Analysis 21 Adjusted Earnings Adjusted earnings for the year ended December 31, 2016 were $2,078 million ($2.28 per common share) compared with $1,866 million for the year ended December 31, 2015 ($2.20 per common share) and $1,574 million ($1.90 per common share) for the year ended December 31, 2014. Adjusted earnings for the fourth quarter of 2016 were $522 million ($0.56 per common share) compared with $494 million ($0.58 per common share) for the fourth quarter of 2015. The year-over-year increases in adjusted earnings reﬂected the operating factors as discussed above in Adjusted EBIT. The impacts of extreme wildﬁres in northeastern Alberta in the second quarter of 2016 on adjusted earnings and adjusted earnings per share for the year ended December 31, 2016 remained unchanged at $26 million and $0.03, respectively. Partially offsetting the adjusted earnings growth discussed above was higher interest expense over the past two years resulting from debt incurred to fund asset growth and the impact of reﬁnancing construction debt with longer-term debt ﬁnancing. The amount of interest capitalized year-over-year also decreased as a result of projects coming into service. Preference share dividends were also higher year-over-year resulting from additional preference shares issued in 2014 and in the fourth quarter of 2016 to fund the Company’s growth capital program. For a detailed discussion on the Company’s ﬁnancing activities, refer to Liquidity and Capital Resources. Also partially offsetting the adjusted EBIT growth was an increase in adjusted income taxes expense which resulted from higher adjusted earnings. This was partially offset by increased tax beneﬁts associated with certain ﬁnancing activities, as well as a higher beneﬁt from the effect of rate-regulated accounting for deferred income taxes. Adjusted Earnings (millions of Canadian dollars) 3 6 5 9 5 8 7 7 6 7 3 6 8 7 0 2 , 6 6 8 , 1 4 7 5 4 1 3 4 , 1 , 1 4 2 1 1 8 0 , 1 , 072 082 092 101 111 121 131 141 151 161 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. Adjusted earnings attributable to noncontrolling interests and redeemable noncontrolling interests decreased in 2016 compared with 2015. The decrease was driven by a full year of a lower public ownership interest in the Fund Group following the execution of the Canadian Restructuring Plan in the third quarter of 2015. Adjusted earnings attributable to noncontrolling interests were higher in the fourth quarter of 2016 when compared with the fourth quarter of 2015, due to stronger operating performance at EEP primarily as a result of a stronger contribution from its liquids business. Despite the increase in the Company’s economic interest in the Fund Group in 2015 as a result of the Canadian Restructuring Plan, the adjusted earnings attributable to the Fund Group’s redeemable noncontrolling interests increased in 2015 compared with 2014 as a result of the positive effects of the Canadian Restructuring Plan and the Fund Group 2014 Drop Down Transaction on the Fund Group’s adjusted earnings. For further details, refer to Canadian Restructuring Plan and The Fund Group 2014 Drop Down Transaction. Available Cash Flow from Operations ACFFO was $879 million for the three months ended December 31, 2016 compared with $876 million for the three months ended December 31, 2015. ACFFO was $3,713 million for the year ended December 31, 2016 compared with $3,154 million for the year ended December 31, 2015. The quarter- over-quarter and year-over-year change in ACFFO was impacted by the growth in adjusted EBIT as discussed in Adjusted EBIT above, as well as other items discussed below. Contributing to the year-over-year increase in ACFFO were lower maintenance capital expenditures in 2016 compared with 2015. Over the last few years, the Company has made a signiﬁcant investment in the ongoing support, maintenance and integrity management of its pipelines and other infrastructure and in the preservation of the service capability of its existing assets. Maintenance capital expenditures decreased in 2016 as higher expenditures in the Company’s Gas Distribution segment were more than offset by lower maintenance capital expenditures in the Liquids Pipelines segment. The lower spending in Liquids Pipelines reﬂected a shift in the timing of maintenance activities to 2017 on certain leasehold improvements, as well as scope reﬁnements to certain planned maintenance projects resulting from ongoing communication with regulators. The Company plans to continue to invest in its maintenance capital program to support the safety and reliability of its operations. 22 Enbridge Inc. 2016 Annual Report ACFFO also includes cash distributions from the Company’s equity Smaller components of Enbridge’s earnings are more exposed investments. The Company’s distributions from such investments to the impacts of commodity price volatility. This includes Energy in 2016 were higher compared with 2015 and reﬂected improved Services, where opportunities to beneﬁt from location, time and performance of such investments, as well as distributions from quality differentials can be affected by commodity market conditions. assets placed into service in recent years. They also include the Company’s interest in Aux Sable’s natural gas Other non-cash adjustments include various non-cash items presented in the Company’s Consolidated Statements of Cash Flows, as well as adjustments for unearned revenues received in each year. extraction and fractionation facilities and natural gas gathering and processing businesses held through EEP; however, the impact on Enbridge’s overall ﬁnancial performance is relatively small and any inherent commodity price risk is mitigated by hedging programs, Partially offsetting the items discussed above, which created commercial arrangements and Enbridge’s partial ownership interest. period-over-period increases in ACFFO, was higher interest expense as discussed in Adjusted Earnings above. Benchmark prices for West Texas Intermediate (WTI) crude fell below US$30 per barrel at the beginning of 2016 and have remained The increase in ACFFO was also partially offset by increased volatile as the market seeks to re-balance supply and demand. distributions to noncontrolling interests in EEP and to redeemable Prices began to recover throughout the year and have climbed noncontrolling interests in the Fund Group. A higher per unit above US$50 per barrel periodically. WTI crude prices averaged distribution and the effects of a strengthening United States US$43 per barrel for 2016 but ended the year above US$53 per dollar versus the Canadian dollar resulted in greater distributions barrel. WTI crude prices averaged US$52.50 per barrel in January to noncontrolling interests in EEP during the ﬁrst half of 2016. 2017. Although Enbridge is exposed to throughput risk under the Higher distributions to redeemable noncontrolling interests in Competitive Toll Settlement (CTS) on the Canadian Mainline and the Fund Group were a result of a higher per unit distribution under certain tolling agreements applicable to other liquids pipelines and increased public ownership in the Fund Group. assets, including Lakehead System, the reduction of investment in ACFFO was $3,154 million for the year ended December 31, 2015 compared with $2,506 million for the year ended December 31, 2014. The year-over-year increase in ACFFO was impacted by the growth in adjusted earnings as discussed in Adjusted EBIT above. Also contributing to the increase in ACFFO in 2015 compared with 2014 was decrease in maintenance capital expenditures due to the completion of speciﬁc maintenance programs in 2014 and higher year-over-year cash distributions received from the Company’s equity investments. Partially offsetting these positive effects were higher interest expense and higher preference share dividends, as well as higher current income taxes expense in 2015 primarily attributable to the Company’s ability to carry back tax losses in the 2014 taxation year to recover prior year taxes paid. Also partially exploration and development programs by the Company’s shippers is not expected to materially impact the ﬁnancial performance of the Company. It is expected that existing conventional and oil sands production should be more than sufficient to support continued high utilization of the Company’s mainline system, and in fact, mainline throughput as measured at the Canada/United States border at Gretna, Manitoba saw record throughput of 2.6 million barrels per day (bpd) in the month of December 2016. Also in 2016, the mainline system has continued to be subject to apportionment of heavy crudes, as nominated volumes currently exceed capacity on portions of the system. Due to the nature of the commercial structures described above, Enbridge’s earnings and cash ﬂow are not expected to be materially affected by the current low price environment. offsetting the period-over-period increase in ACFFO were increased The lower oil prices are also causing some sponsors of oil sands distributions to noncontrolling interests in EEP and to redeemable development programs to reconsider the timing of previously noncontrolling interests in the Fund. Distributions were higher in announced upstream development projects. Cancellation or deferral 2015 compared with the distributions in 2014 mainly as a result of these projects would affect longer-term supply growth from of increased public ownership and distributions per unit in EEP the Western Canadian Sedimentary Basin (WCSB). Enbridge’s and the Fund. Impact of Low Commodity Prices Enbridge’s value proposition is built on the foundation of its reliable 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 business model. The majority of its earnings and cash ﬂow are the potential for some of these projects to be cancelled or deferred generated from tolls and fees charged for the energy delivery in an environment where low prices persist, including EEP’s services that it provides to its customers. Business arrangements Sandpiper Project for which regulatory applications were withdrawn are structured to minimize exposure to commodity price movements in September 2016, Enbridge’s most recent near-term supply and any residual exposure is closely monitored and managed forecast reaffirms that the expansions and extensions of its liquids through disciplined hedging programs. Commercial structures pipeline system that were completed in 2015, as well as the projects are typically designed to provide a measure of protection against currently in progress will provide cost-effective transportation the risk of a scenario where falling commodity prices indirectly services to key markets in North America and will be well utilized. 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. In the current low-price environment, Enbridge is working closely with producers to ﬁnd ways to optimize capacity and provide enhanced access to markets in order to alleviate locational pricing discounts. Examples include the last phase of the Line 6B capacity expansion on EEP’s Lakehead System which was placed into service Management’s Discussion & Analysis 23 in June 2016. This expansion, which is the ﬁnal component of the Eastern Access Program, provides increased access to reﬁneries in the upper midwest United States and eastern Canada. In addition, in February 2017, the Company completed the acquisition of a 27.6% equity interest in the Bakken Pipeline System which, upon completion, will further enhance Enbridge’s strategy of providing efficient market access solutions for Bakken production while providing the opportunity for the implementation of joint tolls with the Energy Transfer Crude Oil Pipeline, and will also enhance market access opportunities for Enbridge’s customers and create a new ﬂow path through the Company’s mainline system to the eastern United States Gulf Coast. For recent developments on this matter, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Bakken Pipeline System. Cash Flows Cash provided by operating activities was $5,211 million for the year ended December 31, 2016, mainly driven by strong operating performance from the Company’s core assets, particularly from Liquids Pipelines and the cash ﬂow generated from growth projects placed into service in recent years. Cash provided by operating activities was also impacted by changes in operating assets and liabilities as further discussed in Liquidity and Capital Resources. In 2016, Enbridge completed certain capital market transactions. The funding raised through these transactions, along with additional borrowings from the Company’s credit facilities, cash generated from operations and cash on hand, were more than sufficient to ﬁnance the Company’s $5.1 billion of capital expenditures in 2016. These funding and cash resources are also expected to provide ﬁnancing ﬂexibility for the Company’s growth capital program in 2017. Highlights of capital market transactions in 2016 include Enbridge’s common shares issuance of approximately $2.3 billion in March and the issuance of $750 million preference shares in November. For the ﬁrst time in over two years, Enbridge also accessed the United States debt markets, issuing in November 2016, two separate US$750 million tranches of senior notes carrying maturity terms of 10 and 30 years, respectively. In December 2016, Enbridge also issued ﬁxed-to-ﬂoating subordinated notes of US$750 million with a maturity of 2077. During 2016, Enbridge, through its sponsored vehicles, issued equity of approximately $0.6 billion. Lastly, Enbridge and its subsidiaries issued approximately $1.1 billion in medium-term notes and extended the average maturity of its secured credit facilities. As discussed in Liquidity and Capital Resources, the Company continues to utilize its sponsored vehicles to enhance its enterprise-wide funding program. To further provide for additional ﬁnancial ﬂexibility, the Company continued to advance its plan to divest approximately $2 billion of non-core assets over a twelve-month period as discussed under Merger Agreement with Spectra Energy – Assets Monetization Plan. Under this plan, in December 2016, EIPLP completed the sale of the South Prairie Region assets to an unrelated party for cash proceeds of $1.08 billion and the Company also entered into agreements to sell approximately $0.6 billion of additional miscellaneous non-core assets and investments. Dividends The Company has paid common share dividends in every year since it became a publicly traded company in 1953. In January 2017, the Company announced a 10% increase in its quarterly dividend to $0.583 per common share, or $2.332 annualized, effective March 1, 2017. As described under Merger Agreement with Spectra Energy, upon close of the Merger Transaction, the Company expects to further increase its quarterly common share dividend by an amount sufficient to bring the aggregate increase in the quarterly dividend to approximately 15% above the then prevailing quarterly rate of $0.530 per common share in 2016. For the 10-year period ended December 2016, the Company’s compound annual average dividend growth rate was 13.9%. As described under the Canadian Restructuring Plan, Enbridge’s current target dividend payout policy range is 40% to 50% of ACFFO. In 2016, the dividend payout was 52.0% (2015 – 50.0%) of ACFFO. For expected impacts to the Company’s dividend payout policy range as a result of the Merger Transaction, refer to Merger Agreement with Spectra Energy. 24 Enbridge Inc. 2016 Annual Report Dividends per Common Share 3 3 2 . 2 1 . 2 6 8 . 1 0 4 . 1 6 2 . 1 3 .1 8 1 9 5 0 8 4 0 7 0 . . . 6 6 0 . 2 6 0 . 07 08 09 10 11 12 13 14 15 16 17e Revenues Forward-Looking Information The Company generates revenues from three primary sources: Forward-looking information, or forward-looking statements, commodity sales, gas distribution sales and transportation and other have been included in this MD&A to provide information about the services. Commodity sales of $22,816 million for the year ended Company and its subsidiaries and affiliates, including management’s December 31, 2016 (2015 – $23,842 million; 2014 – $28,281 million) assessment of Enbridge and its subsidiaries’ future plans and were generated primarily through the Company’s energy services operations. This information may not be appropriate for other purposes. operations. Energy Services includes the contemporaneous purchase Forward-looking statements are typically identiﬁed by words such as and sale of crude oil, natural gas and NGL to generate a margin, ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, which is typically a small fraction of gross revenue. While sales ‘‘target’’, ‘‘believe’’, “likely” and similar words suggesting future outcomes revenues generated from these operations are impacted by commodity or statements regarding an outlook. Forward-looking information or prices, net margins and earnings are relatively insensitive to commodity statements included or incorporated by reference in this document prices and reﬂect activity levels which are driven by differences include, but are not limited to, statements with respect to the following: in commodity prices between locations, grades and points in time, expected EBIT or expected adjusted EBIT; expected earnings/(loss) rather than on absolute prices. Any residual commodity margin risk or adjusted earnings/(loss); expected earnings/(loss) or adjusted is closely monitored and managed. Revenues from these operations earnings/(loss) per share; expected ACFFO; expected future cash depend on activity levels, which vary from year to year depending ﬂows; ﬁnancial strength and ﬂexibility; expected costs related on market conditions and commodity prices. to announced projects and projects under construction; expected 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. in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for the Company’s commercially secured growth program; expected future growth and expansion opportunities; expectations about the Company’s joint venture partners’ ability to complete and ﬁnance projects under construction; expected closing of acquisitions and dispositions; estimated cost and impact to the Company’s overall ﬁnancial performance of complying with the settlement consent decree related to Line 6B and Line 6A; estimated Transportation and other services revenues are earned from future dividends; expected future actions of regulators; expected the Company’s crude oil and natural gas pipeline transportation costs related to leak remediation and potential insurance recoveries; businesses and also include power production revenues from expectations regarding commodity prices; supply forecasts; the the Company’s portfolio of renewable and power generation assets. Merger Transaction and expectation regarding the timing and closing For the Company’s transportation assets operating under market- thereof; expectations regarding the impact of the Merger Transaction based arrangements, revenues are driven by volumes transported including the combined Company’s scale, ﬁnancial ﬂexibility, growth and the corresponding tolls for transportation services. For assets program, future business prospects and performance; dividend payout operating under take-or-pay contracts, revenues reﬂect the terms policy; dividend growth and dividend payout expectation; expectations of the underlying contract for services or capacity. For rate-regulated on impact of hedging program; strategic alternatives currently being assets, revenues are charged in accordance with tolls established evaluated in connection with the United States sponsored vehicles by the regulator, and in most cost-of-service based arrangements strategy and the regulatory framework and recovery of deferred costs are reﬂective of the Company’s cost to provide the service plus by Enbridge Gas New Brunswick Inc. (EGNB). 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 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- derivative fair value gains and losses related to foreign exchange looking statements. By their nature, these statements involve a variety and commodity price contracts used to manage exposures from of assumptions, known and unknown risks and uncertainties and movements in foreign exchange rates and commodity prices. other factors, which may cause actual results, levels of activity and The unrealized mark-to-market accounting creates volatility achievements to differ materially from those expressed or implied and impacts the comparability of revenues in the short-term, by such statements. Material assumptions include assumptions about but the Company believes over the long term, the economic the following: the expected supply of and demand for crude oil, natural hedging program supports reliable cash ﬂows and dividend growth. gas, NGL and renewable energy; prices of crude oil, natural gas, Management’s Discussion & Analysis 25 NGL and renewable energy; exchange rates; inﬂation; interest rates; securities regulators. The impact of any one risk, uncertainty or factor availability and price of labour and construction materials; operational on a particular forward-looking statement is not determinable with reliability; customer and regulatory approvals; maintenance of support certainty as these are interdependent and Enbridge’s future course and regulatory approvals for the Company’s projects; anticipated of action depends on management’s assessment of all information in-service dates; weather; the timing and completion of the available at the relevant time. Except to the extent required by Merger Transaction, including receipt of regulatory approvals applicable law, Enbridge assumes no obligation to publicly update and the satisfaction of other conditions precedent; the realization or revise any forward-looking statements made in this MD&A of anticipated beneﬁts and synergies of the Merger Transaction, or otherwise, whether as a result of new information, future events governmental legislation, acquisitions and the timing thereof; the or otherwise. All subsequent forward-looking statements, whether success of integration plans; cost of complying with the settlement written or oral, attributable to Enbridge or persons acting on consent decree related to Line 6B and Line 6A; impact of the dividend the Company’s behalf, are expressly qualiﬁed in their entirety policy on the Company’s future cash ﬂows; credit ratings; capital by these cautionary statements. project funding; expected EBIT or expected adjusted EBIT; expected earnings/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash ﬂows and expected future ACFFO; and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inﬂation and interest rates impact the Non-GAAP Measures This MD&A contains references to adjusted EBIT, adjusted earnings/ (loss), adjusted earnings/(loss) per common share and ACFFO. Adjusted EBIT represents EBIT adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. Adjusted earnings/(loss) represent earnings or loss attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors included in adjusted EBIT, as well as economies and business environments in which the Company operates adjustments for unusual, non-recurring or non-operating factors and may impact levels of demand for the Company’s services and cost in respect of interest expense, income taxes, noncontrolling of inputs, and are therefore inherent in all forward-looking statements. interests and redeemable noncontrolling interests on a consolidated Due to the interdependencies and correlation of these macroeconomic basis. These factors, referred to as adjusting items, are reconciled factors, the impact of any one assumption on a forward-looking and discussed in the ﬁnancial results sections for the affected statement cannot be determined with certainty, particularly with respect business segments. to the impact of the Merger Transaction on the Company, expected EBIT, adjusted EBIT, earnings/(loss), adjusted earnings/(loss) and associated per share amounts, ACFFO or estimated future dividends. The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labour and ACFFO is deﬁned as cash ﬂow provided by operating activities before changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. construction materials; the effects of inﬂation and foreign exchange Management believes the presentation of adjusted EBIT, adjusted rates on labour and material costs; the effects of interest rates earnings/(loss), adjusted earnings/(loss) per share and ACFFO on borrowing costs; the impact of weather and customer, government gives useful information to investors and shareholders as they and regulatory approvals on construction and in-service schedules provide increased transparency and insight into the performance and cost recovery regimes. Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger Transaction, operating performance, regulatory parameters, dividend policy, project approval and support, renewals of rights of way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, exchange rates, interest rates, commodity prices, political decisions, supply of and demand for commodities and the settlement consent decree related to Line 6B and Line 6A, including but not of the Company. Management uses adjusted EBIT and adjusted earnings/(loss) to set targets and to assess the performance of the Company. Management also uses ACFFO to assess the performance of the Company and to set its dividend payout target. Adjusted EBIT, adjusted EBIT for each segment, adjusted earnings/(loss), adjusted earnings/(loss) per common share and ACFFO are not measures that have standardized meaning prescribed by U.S. GAAP and are not U.S. GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. limited to those risks and uncertainties discussed in this MD&A The tables opposite summarize the reconciliation of the GAAP and in the Company’s other ﬁlings with Canadian and United States and non-GAAP measures. 26 Enbridge Inc. 2016 Annual Report Non-GAAP Reconciliations EBIT to Adjusted Earnings (millions of Canadian dollars) Earnings before interest and income taxes Adjusting items:1 Change in unrealized derivative fair value (gains)/loss2 Sandpiper Project asset impairment3 Gain on sale of South Prairie Region assets Northern Gateway asset impairment Goodwill impairment loss Assets and investment impairment loss Make-up rights adjustments Employee severance and restructuring costs Project development and transaction costs Unrealized intercompany foreign exchange (gains)/loss Northeastern Alberta wildﬁres pipelines and facilities restart costs Warmer/(colder) than normal weather Hydrostatic testing Leak remediation costs, net of leak insurance recoveries (Gains)/loss on sale of non-core assets and investment, net Other Adjusted earnings before interest and income taxes Interest expense Income taxes recovery/(expense) (Earnings)/loss attributable to noncontrolling interest and redeemable noncontrolling interests Discontinued operations Preference share dividends Adjusting items in respect of: Interest expense4 Income taxes5 Discontinued operations Noncontrolling interests and redeemable noncontrolling interests6 Adjusted earnings Three months ended December 31, Year ended December 31, 2016 2015 2016 2015 2014 1,227 277 4 (850) 373 – 56 (1) 52 56 (10) 8 10 (1) (11) – 8 1,198 (412) 32 (406) – (76) 9 (168) – 345 522 841 79 – – – – 88 50 41 2 (21) – 22 23 (21) – 14 1,118 (371) (94) 76 – (74) (1) (36) – (124) 494 4,041 1,635 3,302 (543) 1,004 (850) 373 – 253 130 82 86 43 47 18 (15) (8) 4 (3) 4,662 (1,590) (142) (240) – (293) 45 (378) – 14 2,078 2,017 – – – 440 108 42 41 44 (131) – (15) 72 (26) (88) 17 4,156 (1,624) (170) 410 – (288) 351 (316) – (653) 1,866 36 – – – – 18 35 6 17 (16) – (48) – 92 (38) 5 3,409 (1,129) (611) (203) 46 (251) 203 177 (45) (22) 1,574 1 The above table summarizes adjusting items by nature. For a detailed listing of adjusting items by segment, refer to individual segment discussions. 2 Changes in unrealized derivative fair value gains and loss are presented net of amounts realized on the settlement of derivative contracts during the applicable period. 3 Inclusive of $12 million of related project costs. 4 Interest expense for each period included changes in unrealized derivative fair value gains and losses on interest rate contracts. For the year ended December 31, 2015, interest expense also included a loss of $338 million on de-designation of interest rate hedges from the transfer of assets between entities under common control of Enbridge in connection with the Canadian Restructuring Plan. 5 Income Taxes were impacted by adjustments for unusual, non-recurring and non-operating factors as enumerated under adjusting items for earnings before interest and income taxes. For the year ended December 31, 2016, income taxes also included a recovery of $296 million related to an adjustment for a curing loss as described in footnote 6 below. Adjustments for income taxes also included an out-of-period adjustment of $71 million recognized in the ﬁrst quarter of 2015 in respect of an overstatement of deferred income taxes expense in 2013 and 2014. In the third quarter of 2015, income taxes included an $88 million write-off of a regulatory asset in respect of taxes in connection with the Canadian Restructuring Plan and a valuation allowance of $176 million in respect of deferred income tax assets related to EEP. For the year ended December 31, 2014, income taxes included an expense of $157 million related tax consequences associated with the sale of partnership units between entities under common control of Enbridge. The intercompany gains realized as a result of the transfer between entities were eliminated for accounting purposes, however all tax consequences have remained in consolidated earnings. 6 Noncontrolling interests and redeemable noncontrolling interests were also impacted by adjustments for unusual, non-recurring and non-operating factors as enumerated under adjusting items for earnings before interest and income taxes, as well as adjusting items for interest expense and income taxes. Under EEP’s partnership agreement, capital deﬁcits cannot be accumulated in the capital account of any limited partner and thus, such capital account deﬁcits are brought to zero or “cured”. For the year ended December 31, 2016 , the book value of limited partnership capital accounts in EEP became negative, resulting in a reallocation of such deﬁcit to the Company’s general partnership account in EEP. For the year ended December 31, 2016, earnings attributable to noncontrolling interests were higher by $816 million due to such reallocation. In the case of any additional losses or unanticipated charges to EEP in future periods, curing may occur in such periods. Management’s Discussion & Analysis 27 Adjusted EBIT to ACFFO To facilitate understanding of the relationship between adjusted EBIT and ACFFO, the following table provides a reconciliation of these two key non-GAAP measures. (millions of Canadian dollars) Adjusted earnings before interest and income taxes Depreciation and amortization1 Maintenance capital2 Interest expense3 Current income taxes3 Distributions to noncontrolling interests Distributions to redeemable noncontrolling interests Preference share dividends Cash distributions in excess of equity earnings3 Other non-cash adjustments Available cash ﬂow from operations (ACFFO) 1 Depreciation and amortization: Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other 2 Maintenance capital: Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Eliminations and Other 3 These balances are presented net of adjusting items. Three months ended December 31, Year ended December 31, 2016 2015 2016 2015 2014 1,198 564 (205) 1,557 (403) (31) (182) (54) (76) 67 1 879 344 88 70 48 1 13 564 (76) (88) (17) (2) (22) (205) 1,118 541 (200) 1,459 (372) (53) (179) (34) (74) 64 65 876 336 78 70 47 – 10 541 (44) (118) (17) – (21) (200) 4,662 2,240 (671) 6,231 (1,545) (92) (720) (202) (293) 183 151 4,156 2,024 (720) 5,460 (1,273) (160) (680) (114) (288) 244 (35) 3,409 1,577 (970) 4,016 (926) (12) (535) (79) (245) 196 91 3,713 3,154 2,506 1,369 339 292 190 2 48 2,240 (207) (339) (48) (5) (72) (671) 1,227 308 272 186 (1) 32 2,024 (278) (302) (45) – (95) (720) 911 304 221 124 (2) 19 1,577 (500) (296) (62) (1) (111) (970) 28 Enbridge Inc. 2016 Annual Report Available Cash Flow from Operations The following table provides a reconciliation of cash provided by operating activities (a GAAP measure) to ACFFO. (millions of Canadian dollars) Cash provided by operating activities – continuing operations Adjusted for changes in operating assets and liabilities1 Distributions to noncontrolling interests Distributions to redeemable noncontrolling interests Preference share dividends Maintenance capital expenditures2 Signiﬁcant adjusting items: Weather normalization Project development and transaction costs Realized inventory revaluation allowance3 Employee severance and restructuring costs Other items Available cash ﬂow from operations (ACFFO) Three months ended December 31, Year ended December 31, 2016 2015 2016 2015 2014 1,058 272 1,330 (182) (54) (76) (205) 7 44 1 43 (29) 879 772 508 1,280 (179) (34) (74) (200) 16 2 (52) 30 87 876 5,211 362 5,573 (720) (202) (293) (671) 13 74 (345) 73 211 3,713 4,571 688 5,259 (680) (114) (288) (720) (11) 44 (474) 30 108 2,528 1,777 4,305 (535) (79) (245) (970) (36) 19 – 6 41 3,154 2,506 1 Changes in operating assets and liabilities include changes in environmental liabilities, net of recoveries. 2 Maintenance capital expenditures are expenditures that are required for the ongoing support and maintenance of the existing pipeline system or that are necessary to maintain the service capability of the existing assets (including the replacement of components that are worn, obsolete or completing their useful lives). For the purpose of ACFFO, maintenance capital excludes expenditures that extend asset useful lives, increase capacities from existing levels or reduce costs to enhance revenues or provide enhancements to the service capability of the existing assets. 3 Realized inventory revaluation allowance relates to losses on sale of previously written down inventory for which there is an approximate offsetting realized derivative gain in ACFFO. Management’s Discussion & Analysis 29 Corporate Vision and Strategy Vision Enbridge’s vision is to be the leading energy delivery company in North America. In pursuing this vision, the Company plays a critical role in enabling the economic well-being and quality of life of North Americans, who depend on access to plentiful energy. The Company transports, distributes and generates energy, and its primary purpose is to deliver the energy North Americans need in the safest, most reliable and most efficient way possible. Among its peers, Enbridge strives to be the leader, which means not only leadership in value creation for shareholders but also leadership with respect to worker and public safety and environmental protection associated with its energy delivery infrastructure, as well as in customer service, community investment and employee satisfaction. Driven by this vision, the Company delivers value for shareholders from a proven and unique value proposition, which combines visible growth, a reliable business model and generation of a dependable and growing income stream. Strategy The Company’s initiatives centre around eight areas of strategic emphasis in four key focus areas. Strategies are reviewed at least annually with direction from the Company’s Board of Directors. Commitment to Safety and Operational Reliability • Focus on project management • Preserve ﬁnancing strength and ﬂexibility • Strengthen core businesses • Enhance strategic growth platforms Execute Secure the Longer-Term Future Maintain the Foundation • Uphold Enbridge values • Maintain the Company’s social license to operate • Attract, retain and develop highly capable people Commitment to Safety and Operational Reliability Safety and operational reliability remains the Company’s number one priority and sets the foundation for the strategic plan. The commitment to safety and operational reliability means achieving and maintaining industry leadership in safety (process, public and personal) and ensuring the reliability and integrity of the systems the Company operates in order to generate, transport and deliver the energy society counts on and to protect the environment. Under the umbrella of the Company’s Operational Risk Management Plan (ORM Plan) introduced in 2010, Enbridge has undertaken extensive maintenance, integrity and inspection programs across its pipeline systems. The ORM Plan has resulted in strong improvements in the area of safety and operational risk management, a bolstering of incident response capabilities, employee and public safety protocols and improved communications with landowners and ﬁrst responders. In addition, an enterprise-wide safety and risk management framework has been implemented to ensure the Company identiﬁes, prioritizes and effectively prevents and mitigates risks across the enterprise. The Company strives to embed a common risk management framework within its operations and those of its joint venture partners. Supporting these initiatives is a safety culture that strives towards a target of 100% safe operations, with a belief that all incidents can be prevented. To achieve the goal of industry leadership, the Company measures its performance as compared to standard industry performance, transparently reports its results and continues to use external assessments to measure its performance. 30 Enbridge Inc. 2016 Annual Report Execute Focus on Project Management growth platforms, including liquids and gas pipelines, United States and Canadian midstream businesses, an attractive portfolio of regulated natural gas distribution utilities and a growing renewable Enbridge’s objective is to safely deliver projects on time and on power generation business. The strength of the combined assets and budget and at the lowest practical cost while maintaining the highest geographic footprint will generate highly transparent and predictable standards for safety, quality, customer satisfaction and environmental cash ﬂows underpinned by hiqh-quality commercial constructs that and regulatory compliance. With a signiﬁcant portfolio of commercially align closely with Enbridge’s investor value proposition and signiﬁcant secured growth projects, successful project execution is critical to on-going organic growth potential. achieving the Company’s long-term growth plan. These projects are predominantly liquids focused, but increasingly include green energy, Strengthen Core Businesses natural gas, offshore and gas distribution initiatives. Enbridge, through Within the Company’s pre-merger crude oil transportation business, its Major Projects Group, continues to build upon and enhance strategies to strengthen the core business are focused on optimizing the key elements of its rigorous project management processes, asset performance, strengthening stakeholder and customer including: employee and contractor safety; long-term supply chain relationships and providing access to new markets for production agreements; quality design, materials and construction; extensive from western Canada and the Bakken regions, all while ensuring safe regulatory and public consultation; robust cost, schedule and risk and reliable operations. The Company’s asset optimization efforts controls; and efficient project transition to operating units. Ongoing focus on maximizing the operational and ﬁnancial performance of work to ensure Enbridge’s project execution costs remain competitive its infrastructure assets within established risk parameters, providing in any market environment is a priority. Preserve Financing Strength and Flexibility The maintenance of adequate ﬁnancing strength and ﬂexibility is crucial to Enbridge’s growth strategy. Enbridge’s ﬁnancing strategies are designed to ensure the Company has sufficient ﬁnancial ﬂexibility to meet its capital requirements. To support this objective, the Company develops ﬁnancing plans and strategies to manage credit ratings, diversify its funding sources and maintain substantial standby bank credit capacity and access to capital markets in both Canada and the United States. Sponsored vehicles also remain a critical component to ensuring efficient and low-cost access to ﬁnancial markets. For further discussion on the Company’s ﬁnancing strategies, refer to Liquidity and Capital Resources. As part of the Company’s risk management policy, the Company engages in a comprehensive long-term economic hedging program to mitigate the impact of ﬂuctuations in interest rates, foreign exchange and commodity price on the Company’s earnings. This economic hedging program together with ongoing management of credit exposures to customers, suppliers and counterparties helps enable cost effective capital raising by supporting one of the key tenets of the Company’s investor value proposition, a reliable business model. For further details, refer to Risk Management and Financial Instruments. The Company continually assesses ways to generate value for shareholders, including reviewing opportunities that may lead to acquisitions, dispositions or other strategic transactions, some of which may be material. Opportunities are screened, analysed and assessed using strict operating, strategic and ﬁnancial criteria with the objective of ensuring the effective deployment of capital and the enduring ﬁnancial strength and stability of the Company. Secure the Longer-Term Future A key strategic priority is the development and enhancement of strategic growth platforms from which to secure the Company’s competitive services and value to customers. The Company’s assets are strategically located and well-positioned to capitalize on opportunities. In 2016, despite unfavourable commodity market conditions, Enbridge’s Mainline delivered record volumes of crude into United States markets. The Company’s existing footprint, access to major North American markets, and the ability to incrementally enhance its capacity through low-cost expansions provide Enbridge’s customers with an attractive and reliable path to market. While executing its record growth capital program in the recent years, the Company has also been undertaking an extensive integrity program across its liquids and gas systems. The Line 3 Replacement Program (L3R Program) being undertaken by Enbridge and EEP will support the safety and operational reliability of the mainline system, enhance ﬂexibility, allow Enbridge and EEP to optimize throughput on the mainline system and restore approximately 370,000 bpd of capacity from western Canada into Superior, Wisconsin. For further details on the L3R Program, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Line 3 Replacement Program. The strategic focus within Regional Oil Sands Systems is to optimize existing asset corridors and provide innovative, creative, competitive and customer oriented solutions to WCSB producers to secure the incremental supply of crude oil expected from the western Canadian oil sands projects over the next decade. Within this regional focus area, Enbridge has approximately $3.7 billion of regional infrastructure growth projects currently under development, including Enbridge’s 70% share of the Norlite project, which is expected to enter service in 2017. In the Bakken region, Enbridge and EEP’s growth is focused on the completion of the US$1.5 billion investment in the Bakken Pipeline System, in partnership with Energy Transfer. The Bakken Pipeline System will provide North Dakota producers enhanced access to premium light crude oil markets in both the eastern and western United States Gulf Coast. For recent developments on this matter, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Bakken Pipeline System (EEP). long-term future. As discussed under Merger Agreement with In addition to executing its secured growth program, the Company Spectra Energy, on September 6, 2016, Enbridge announced is focused on extending growth beyond 2019 through continued a deﬁnitive merger agreement with Spectra Energy. The combined expansion of liquids pipelines, as well as development of its current company is expected to beneﬁt from a diversiﬁed set of strategic and future natural gas and power businesses. The acquisition of Management’s Discussion & Analysis 31 Spectra Energy will provide Enbridge with a leading North American and regulatory approvals, the investment signiﬁcantly extends gas infrastructure franchise. Enbridge plans to expand and extend the Company’s offshore wind generation business which began with the Spectra Energy gas pipelines to serve growing demand markets the acquisition of a 24.9% interest in the 400-MW Rampion Offshore in the United States, Canada and Mexico. Natural gas demand is Wind Project (Rampion Project) in the United Kingdom in 2015. anticipated to grow steadily through the next decade and Spectra The Rampion Project is anticipated to enter into service in 2018. Energy’s assets are well positioned for continued proﬁtable expansion. The Company’s energy marketing business also plans to expand The Company continues to focus on expanding its Canadian its business through obtaining capacity on energy delivery and Midstream footprint, primarily within the Montney and Duvernay storage assets in strategic locations to grow margins generated formations, two of the most competitive natural gas and NGL from location, grade and time differentials. plays in North America. Even in an environment of depressed prices, the Montney play continues to attract signiﬁcant drilling activity. Maintain the Foundation In 2016, the Company acquired two operating natural gas plants Uphold Enbridge Values (the Tupper plants) and associated pipelines in northeastern British Columbia. The Company also continues to pursue ultra-deep water offshore natural gas and crude oil transmission opportunities. In 2016, the Company placed the Heidelberg Pipeline into service and the Stampede Oil Pipeline (Stampede Pipeline) is expected to be operational by 2018. Spectra Energy’s western Canadian franchise adds a very signiﬁcant scale to Enbridge’s existing Canadian midstream business and it will position Enbridge as the leading gas processing company in the WCSB, with multiple infrastructure expansion and new construction opportunities. Enbridge 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 Enbridge’s natural gas distribution business in eastern Canada is on Business Conduct. the largest in Canada with over two million customers. EGD’s Greater Toronto Area (GTA) project, which was completed in March 2016, Maintain the Company’s Social License to Operate is a key component of EGD’s gas supply strategy and will provide Earning and maintaining “social license” – the acceptance by new transmission services that will enable access to mid-continent the communities in which the Company operates or is proposing gas supplies for the utility and its customers. Spectra Energy’s Union new projects – is critical to Enbridge’s ability to execute on its Gas also operates within a highly attractive franchise area that offers growth plans. To continually earn public acceptance, the Company considerable rate-base growth opportunities. is increasingly focused on building long-term relationships by Enhance Strategic Growth Platforms understanding, accommodating and resolving public concerns related to the Company’s projects and operations. The Company The development of new platforms to diversify and sustain long-term engages its key stakeholders through collaboration and by growth is an important strategic priority. The Merger Transaction demonstrating openness and transparency in its communication. acquisition goes a long way to achieving Enbridge’s diversiﬁcation Enbridge also focuses on enhancing the effectiveness of the objectives. It will position the Company with approximately 50% Government Relations function with a goal of advocating company non-liquids infrastructure assets. It will also signiﬁcantly increase positions on key issues and policies that are critical to its business. Enbridge’s footprint in growing United States markets such The Company also strives to build awareness of the role energy as Florida and the Northeast. The Company will continue focusing on enhancing these new and Enbridge play in people’s lives in order to promote better understanding of the Company and its businesses. platforms and also on its development and diversiﬁcation efforts To earn the public’s trust, and to help protect and reinforce the to secure investment in additional renewable energy generation Company’s reputation with its stakeholders, Enbridge is committed and Liqueﬁed natural gas (LNG) development. Currently, Enbridge to integrating Corporate Social Responsibility (CSR) into every is expanding its renewable power efforts offshore of Europe aspect of its business. The Company deﬁnes CSR as conducting under low-risk commercial structures with highly credit-worthy business in an ethical and responsible manner, protecting the counterparties. In February 2017, the Company announced it had environment and the safety of people, providing economic and acquired an effective 50% interest in the partnership that holds other beneﬁts to the communities in which the Company operates, the 497-MW Hohe See Offshore Wind Project in Germany, with supporting universal human rights and employing a variety of policies, a targeted in-service date in 2019. In 2016, Enbridge expanded its programs and practices to manage corporate governance interests and development expertise in renewable power generation and ensure fair, full and timely disclosure. The Company provides with the acquisitions of a 50% interest in a French offshore wind its stakeholders with open, transparent disclosure of its CSR development company. Along with EDF, Enbridge will co-develop performance and prepares its annual CSR Report using the Global three large scale offshore wind farms off the coast of France that Reporting Initiative G4 sustainability reporting guidelines, which serve would produce a combined 1,428 MW of power. While development as a generally accepted framework for reporting on an organization’s of these projects is still subject to ﬁnal investment decision economic, environmental and social performance. 32 Enbridge Inc. 2016 Annual Report The Company also executes programs and initiatives to ensure the perspective of its stakeholders help guide business decision Industry Fundamentals making on sustainable development issues. With this in mind, Supply and Demand for Liquids in 2016 the Company launched the development of a new generation of environmental goals that reﬂect the shifting energy landscape in North America, including changing business needs and growing public interest in Enbridge’s role in climate and energy issues. As part of this process, the Company updated its corporate Climate Policy in 2016, to more rigorously outline the steps Enbridge is taking to address climate change, including reducing its own carbon footprint and undertaking activities and engagement with external stakeholders on water protection. The next generation of Enbridge’s environmental goals will succeed the Company’s Neutral Footprint Program, originally adopted in 2009, through which Enbridge committed to help reduce the environmental impact of its liquids pipeline expansion projects within ﬁve years of their occurrence by meeting certain goals for replacing trees, conserving land and generating kilowatt hours of green energy. Enbridge has an established and successful history of being the largest transporter of crude oil to the United States, the world’s largest market. While United States’ demand for Canadian crude oil production will support the use of Enbridge infrastructure for the foreseeable future, North American and global crude oil supply and demand fundamentals are shifting, and Enbridge has a role to play in this transition by developing long-term transportation options that enable the efficient ﬂow of crude oil from supply regions to end-user markets. As discussed in Performance Overview – Impact of Low Commodity Prices, the downturn in price has impacted Enbridge’s liquids pipelines’ customers, who have responded by reducing their exploration and development spending for 2016 and into 2017. The international market for crude oil has seen a signiﬁcant increase in production from North American basins and increased production from the Enbridge provides annual progress updates related to the above Organization of Petroleum Exporting Countries (OPEC) in the face initiatives in the Company’s annual CSR Reports which can be found at csr.enbridge.com. Unless otherwise speciﬁcally stated, none of the information contained on, or connected to, the Enbridge website is incorporated by reference in, or otherwise part of, this MD&A. Attract, Retain and Develop Highly Capable People of slower global demand growth. Benchmark prices for WTI crude fell below US$30 per barrel at the beginning of 2016 and have remained volatile as the market seeks to re-balance supply and demand. Prices began to recover throughout the year, in response to anticipated cuts in OPEC country production among other factors, and have climbed above US$50 per barrel for short periods of time. WTI crude prices averaged US$43 per barrel for 2016 and ended Investing in the attraction, retention and development of the year above US$53 per barrel, with WTI crude prices averaging employees and future leaders is fundamental to executing Enbridge’s US$52.50 per barrel in January 2017. growth strategy and creating sustainability for future success. In 2016, Enbridge launched its Building Our Energy Future program, which is aimed to improve and enhance the Company’s competitiveness in the industry so it can continue to serve its stakeholders well and further strengthen its foundation for the future. As one of the initiatives under this program, the Company redesigned its organizational structure around new operating models for service delivery. As a consequence, in October 2016 the Company reduced its workforce by approximately 5%. Notwithstanding the low price environment, the Enbridge mainline system has thus far continued to be highly utilized and in fact, mainline throughput as measured at the Canada/United States border at Gretna, Manitoba saw record throughput of 2.6 million bpd in the month of December 2016. The mainline system continues to be subject to apportionment of heavy crudes, as nominated volumes currently exceed capacity on portions of the system. The impact of low crude oil prices on the ﬁnancial performance of Enbridge’s liquids pipelines business is expected to be relatively The Company focuses on enhancing the capability of its people modest given the commercial arrangements which underpin to maximize the potential of the organization and undertakes various many of the pipelines that make up the liquids system and provide activities such as offering accelerated leadership development a signiﬁcant measure of protection against volume ﬂuctuations. programs, enhancing career opportunities and building change In addition, the Company’s mainline system is well positioned management capabilities throughout the enterprise so that projects to continue to provide safe and efficient transportation which will and initiatives achieve intended beneﬁts. Furthermore, Enbridge enable western Canadian and Bakken production to reach attractive strives to maintain industry competitive compensation and retention markets in the United States and eastern Canada at a competitive programs that provide both short-term and long-term performance cost relative to other alternatives. The fundamentals of oil sands incentives to its employees. production and low crude oil prices have caused some sponsors to reconsider the timing of their upstream oil sands development projects. However, recently updated forecasts continue to reﬂect long-term supply growth from the WCSB, although the projected pace of growth is slower than previous forecasts as companies continue to assess the viability of certain capital investments in the current low price environment. Management’s Discussion & Analysis 33 Over the long term, global energy consumption is expected to continue to grow, with the growth in crude oil demand primarily driven by emerging economies in regions outside the Organization for Economic Cooperation and Development (OECD), mainly India and China. While OECD countries, including Canada, the United States and western European nations, will experience population growth, the emphasis placed on energy efficiency, conservation and a shift to lower carbon fuels, such as natural gas and renewables, will reduce crude oil demand over the long term. Accordingly, there is a strategic opportunity for North American producers to grow production to displace foreign imports and participate in the growing global demand outside North America. In terms of supply, long-term global crude oil production is expected to continue to grow through 2035, with growth in supply primarily contributed by North America, Brazil and OPEC. Growth in North America is largely driven by production from the oil sands and the continued development of tight oil plays including the Permian, Bakken and Eagle Ford formations. Growth in supply from OPEC is primarily a result of a shift in OPEC’s strategy from ‘balancing supply’ to ‘competing for market share’ in Asia and Europe. However, political uncertainty in certain oil producing countries, including Libya and Iraq, increases risk in those regions’ supply growth forecasts and makes North America one of the most secure supply sources of crude oil. As witnessed throughout 2016 and early 2017, North American supply growth can be inﬂuenced by macro-economic factors that drive down the global crude prices. OPEC has since changed its strategy after its November 2016 meeting in which OPEC agreed to cut production by 1.2 million bpd effective January 2017. Over the longer term, North American production from tight oil plays, including the Bakken, is expected to grow as technology continues to improve well productivity and reduce costs. The WCSB, in Canada, is viewed as one of the world’s largest and most secure supply sources of crude oil. However, the pace of growth in North America and level of investment in the WCSB could be tempered in future years by a number of factors including a sustained period of low crude oil prices and corresponding production decisions by OPEC, increasing environmental regulation, prolonged approval processes for new pipelines and the continuation of access restrictions to tide-water in Canada for export. In recent years, the combination of relatively ﬂat domestic demand, growing supply and long- lead time to build pipeline infrastructure led to a fundamental change in the North American Canadian Crude Oil Production (thousands of barrels per day) 9 8 8 4 , 7 5 7 3 , 3 7 8 3 , 1 6 0 4 , 14 15 16 17e ■ Oil Sands ■■ ■■ ■ Other crude oil landscape. The inability to move increasing inland supply to tide-water markets Source: National Energy Board resulted in a divergence between WTI and world pricing, resulting in lower netbacks for North American producers than could otherwise be achieved if selling into global markets. The impact of price differentials has been even more pronounced for western Canadian producers as insufficient pipeline infrastructure resulted in a further discounting of Alberta crude against WTI. With a number of market access initiatives completed by the industry in recent years, including those introduced by Enbridge, the crude oil price differentials signiﬁcantly narrowed in 2015, and resulted in higher netbacks for producers. The differentials between WTI and world pricing remained narrow in 2016. This has resulted in crude oil continuing to move off of alternative transportation networks such as rail to ﬁll the additional pipeline capacity as it became available. However, Canadian pipeline export capacity is expected to remain essentially full, resulting in incremental production utilizing non-pipeline transportation services until such time as pipeline capacity is made available. As the supply in North America continues to grow, the growth and ﬂexibility of pipeline infrastructure will need to keep pace with the sensitive demand and supply balance. Over the longer term, the Company believes pipelines will continue to be the most cost-effective means of transportation in markets where the differential between North American and global oil prices remain narrow. Utilization of rail to transport crude is expected to be substantially limited to those markets not readily accessible by pipelines. Enbridge’s role in helping to address the evolving supply and demand fundamentals and alleviating price discounts for producers and supply costs to reﬁners is to provide expanded pipeline capacity and sustainable connectivity to alternative markets. As discussed in Growth Projects – Commercially Secured Projects, in 2016, Enbridge continued to execute its growth projects plan in furtherance of this objective. 34 Enbridge Inc. 2016 Annual Report Supply and Demand for Natural Gas and NGL Global energy demand is expected to increase 30% by 2040, according to the International Energy Agency, driven primarily by economic growth in non-OECD countries. Natural gas will play an important role in meeting this energy demand as gas consumption is anticipated to grow by 50% during this period as one of the world’s fastest growing energy sources, second only to renewables. Most natural gas demand will stem from the need for greater power generation capacity, as natural gas is a cleaner alternative to coal, which currently has the largest market share for power generation. Within North America, United States natural gas demand growth is expected to be driven by the next wave of gas-intensive petrochemical facilities which are now starting to enter service, along with power generation, an increase in the volume of LNG exports and additional pipeline exports to Mexico. Within Canada, natural gas demand growth is expected to be largely tied to oil sands development and growth in gas-ﬁred power generation. Canadian gas demand growth will be accelerated with implementation of proposed government regulations to replace coal ﬁred power, designed to meet emissions targets. North American supply from tight formations continues to create a demand and supply imbalance for natural gas and some NGL products. North American gas supply continues to be signiﬁcantly impacted by development in the northeastern United States, primarily the proliﬁc Marcellus shale, and the rapidly growing Utica shale. The abundance of supply from these shale plays continues to fundamentally alter natural gas ﬂow patterns in North America, as this region has largely displaced ﬂows from the Gulf Coast and WCSB that historically supplied to eastern markets. Similar pressures are also being North American Natural Gas Production (billions of cubic feet per day) . 8 4 8 .1 9 8 . 7 6 8 . 7 0 9 14 15 16 17e ■■ ■ Shale ■■ ■ Other felt in the Midwest and southern markets. Additional production is expected from this region as pipeline constraints are eliminated, with several proposed pipeline projects targeted Sources: Energy Information Administration (United States), National Energy Board (Canada) for in-service over the next two years. Natural gas production from regions other than the northeastern United States has largely been ﬂat or has declined over the past several years in the face of lower-cost production from the Appalachian region, in addition to prolonged weak North American natural gas prices. The extended low commodity price environment in the basins in which the US Midstream business operates has resulted in reduced drilling activity and low volumes on the US Midstream business’s systems. One exception is WCSB production, reaching an all-time record high in early 2016, which was triggered by the combination of new infrastructure and the connection of previously drilled wells. Producers remain focused on the Montney shale and the developing Duvernay, where core areas are among the most competitive within North America. Economic drivers vary, but include: continuous productivity improvements, extremely low cost dry gas plays and abundant liquids and/or condensate rich gas resources, where liquid products enhance or drive economics. The highly proliﬁc Permian Basin in West Texas/Southeast New Mexico is also experiencing signiﬁcant beneﬁt from technology improvements, where producer focus is primarily crude oil, however, with signiﬁcant production of NGL-rich associated gas. In the longer term, while low natural gas prices are expected to be a key driver in future natural gas demand and infrastructure growth, producer break-even costs continue to decline and as a result it is expected there will continue to be ample economic supply that will respond quickly to rising demand, thereby limiting price advances. Natural gas prices have been relatively weak over the last year as a result of warm weather and high storage inventories; however, although rig counts have trended lower, production levels have remained generally ﬂat due to productivity gains, the high number of drilled and uncompleted wells and continued focus on liquids-rich and condensate plays. NGL that can be extracted from liquids-rich gas streams include ethane, propane, butane and natural gasoline, which are used in a variety of industrial, commercial and other applications. The robust gas production has created regional supply imbalances for some NGL products and weakened the economics of NGL extraction, although these imbalances modestly improved over the second half of 2016 as crude prices have rebounded and NGL export capacity has expanded. Management’s Discussion & Analysis 35 Over the longer term, the growth in NGL demand is expected plays in the WCSB and Bakken, and is uniquely positioned to be robust, driven largely by incremental ethane demand. Ethane is to transport liquids-rich gas. Alliance Pipeline has developed new the key feedstock to the United States Gulf Coast petrochemical service offerings to best meet the needs of producers and shippers, industry, which is the world’s second lowest-cost ethylene production and demand for transportation services continues to be robust. region and is currently undergoing signiﬁcant expansion that has The focus on liquids-rich gas development also creates opportunities started to enter service and will accelerate in 2017. When this new for Aux Sable, an extraction and fractionation facility near Chicago, infrastructure is completed and fully online in late 2018, ethane prices Illinois near the terminus of Alliance Pipeline, which provides and resulting extraction margins are expected to improve, reducing producers with access to premium NGL markets. Vector is also the amount of ethane retained in the gas stream. In addition, well positioned to deliver increasing Marcellus and Utica production the inaugural export cargo of ethane was shipped in March 2016 to eastern markets. and if waterborne exports rise signiﬁcantly, the ethane market will further tighten. Similarly, rapidly growing supplies of propane Supply and Demand for Renewable Energy have been outpacing demand leading to record storage levels and The power generation and transmission network in North America downward pressure on prices. The outlook for abundant propane is expected to undergo signiﬁcant growth over the next 20 years. supplies in excess of domestic demand has prompted the development On the demand side, North American economic growth over and expansion of export facilities for liqueﬁed petroleum gas (LPG). the longer term is expected to drive growing electricity demand, Over a few short years, the United States has become the world’s although continued efficiency gains are expected to make the largest LPG exporter, with volumes reaching over one million bpd economy less energy-intensive and temper demand growth. at times in 2016, which have helped to reduce the inventory overhang On the supply side, impending legislation in Canada is expected and provide support to propane prices. In Canada, the WCSB is well-situated to capitalize on the evolving NGL fundamentals over the longer term as the Montney and Duvernay shale plays contain signiﬁcant liquids-rich resources at competitive extraction costs. Longer-term, NGL fundamentals indicate a positive outlook for demand growth, and would be further supported with a continued recovery in crude oil 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. prices. Consequently, the crude-to-gas price ratio is expected North American wind and solar resources fundamentals remain to remain well above energy conversion value levels and continue strong. In the United States there is over 82 gigawatts (GW) to be supportive of NGL extraction over the longer term. of installed wind power capacity and in Canada over 11 GW Conditions for western Canadian LNG exports remain favourable, as industry proponents continue to assess updated project economics considering a scale down in construction costs, ample low-cost gas supplies and a stabilizing market, as supply/demand forecasts show signs of rebalancing. Proponents who have the beneﬁt of an integrated model (upstream supply and downstream market) have the greatest probability of making a favourable ﬁnal investment decision. There continues to be regional opposition to proposed projects in general, primarily stemming from a climate change/greenhouse gas (GHG) emissions agenda, mixed with some local Indigenous opposition as it relates to environmental impacts on wildlife and ﬁsh habitats. The Government of British Columbia continues to advocate strongly for west coast LNG. The short term outlook for LNG fundamentals points to a continued oversupply, as it will take some time for the market to fully absorb the large volumes of new supply coming online. Post-2025, forecasts indicate demand will exceed projected supply as growing markets seek to diversify supply sources. This should be supportive of Canadian LNG exports. of installed wind power capacity. Solar resources in southwestern states such as Arizona, California and Nevada are considered to be some of the best in the world for large-scale solar plants and the United States currently has over 35 GW of installed solar photovoltaic capacity. In late 2015, the United States passed legislation extending the availability of certain Federal tax incentives which have supported the proﬁtability of wind and solar projects. However, expanding renewable energy infrastructure in North America is not without challenges. Growing renewable generation capacity is expected to necessitate substantial capital investment to upgrade existing transmission systems or, in many cases, build new transmission lines, as these high quality wind and solar resources are often found in regions that are not in close proximity to markets. In the near-term, uncertainty over the availability of tax or other government incentives in various jurisdictions, the ability to secure long-term power purchase agreements (PPAs) through government or investor-owned power authorities and low market prices of electricity may hinder the pace of future new renewable capacity development. However, continued improvement In response to these evolving natural gas and NGL fundamentals, in technology and manufacturing capacity in the past few years Enbridge believes it is well-positioned to provide value-added has reduced capital costs associated with renewable energy solutions to producers. Enbridge is responding to the need infrastructure and has also improved yield factors of power for regional infrastructure with additional investment in Canadian generation assets. These positive developments are expected and United States midstream processing and pipeline facilities. to render renewable energy more competitive and support ongoing Alliance Pipeline traverses through the heart of key liquids-rich investment over the long term. 36 Enbridge Inc. 2016 Annual Report In Europe, the future outlook for renewable energy, especially from In 2017, the Company expects to place into service approximately offshore wind in countries with long coastlines and densely populated $5.6 billion of growth projects, inclusive of Enbridge’s 70% share areas, is very positive. According to the European Wind Energy of the $1.3 billion Norlite project, as well as the Company’s investment Association, by 2030, wind energy capacity in Europe is expected in the Bakken Pipeline System. In January 2017, the Company to be 320 GW, including 66 GW of offshore capacity. There is completed the Athabasca Pipeline Twin portion of the Regional Oil also wide public support for carbon reduction targets and broader Sands Optimization Project, whereas the Wood Buffalo Extension adoption of renewable generation across all governmental levels. component is now expected to be in service in December 2017. Furthermore, governments in Europe are seeking to rationalize Beyond 2017, the Company will continue to execute its liquids the contribution of nuclear power to the overall energy mix, which pipelines market access strategy through the completion has resulted in an increased focus on alternative sources such of the L3R Program. as large scale offshore wind. Enbridge continues to expand its renewable asset footprint Within the Gas Distribution segment, the completion of the GTA project in 2016 has enabled EGD to meet the growing demand and is one of Canada’s largest wind and solar power generators. for natural gas distribution services in the GTA while ensuring In February 2017, the Company announced it had acquired an effective 50% interest in the partnership that holds the 497-MW Hohe See Offshore Wind Project in Germany. Earlier in 2016, the ongoing safe and reliable delivery of natural gas to its current and future customers. The system expansion is the largest ever undertaken by EGD and it signiﬁcantly bolsters EGD’s rate base Enbridge announced the acquisition of the 249-MW Chapman Ranch and expected earnings going forward. Wind Project in Texas, as well as the acquisition of a 50% interest in a French offshore wind development company, Éolien Maritime France SAS (EMF). In late 2015, Enbridge announced acquisitions of the 103-MW New Creek Wind Project in West Virginia and a 24.9% interest in the 400-MW Rampion Project in the United Kingdom. The New Creek Wind Project was subsequently completed and placed into service in December 2016. Including these acquisitions, Enbridge has invested over $5 billion in renewable power generation and transmission since 2002. The Company will continue to seek new opportunities to expand its power generation business and growing its portfolio by investing in assets that meet its investment criteria. Growth Projects— Commercially Secured Projects A key element of Enbridge’s corporate strategy is the successful execution of its growth capital program. In 2016, Enbridge successfully placed into service over $2 billion of growth projects across several business units. With approximately $10 billion of growth projects placed into service over the last two years, Enbridge portfolio of approximately $27 billion of growth projects includes $17 billion of growth projects expected to be placed into service between 2017 and 2019. In 2016, Enbridge also expanded its natural gas pipelines and processing businesses with the acquisition of the Tupper Plants and associated pipelines in the Montney region of northeastern British Columbia from a Canadian subsidiary of Murphy Oil Corporation. Together, the two plants have capacity of 320 million cubic feet per day and will serve to enhance the Company’s natural gas footprint within the Montney region, one of the most attractive natural gas plays in North America. Other projects completed within the Gas Pipelines and Processing segment included the 100,000 bpd Heidelberg Pipeline in the Gulf of Mexico and the expansion of the Aux Sable Extraction Plant in Channahon, Illinois, providing approximately 24,500 bpd of incremental fractionation capacity to this plant. In keeping with the Company’s strategic priority to enhance strategic growth platforms and sustain long-term growth, Enbridge continues to expand its renewable energy generation capacity. Within the Green Power and Transmission segment, the New Creek Wind Project entered service in December 2016, increasing Enbridge’s net operating renewable power generating capacity to approximately 1,900-MW. Also in 2016, Enbridge announced the acquisition of the 249-MW Chapman Ranch Wind Project in Texas. Construction on the Company’s previously announced 24.9% In 2016, within the Liquids Pipelines segment, EEP completed interest in the 400-MW Rampion Project in the United Kingdom and placed into service the expansion of Line 6B on the Lakehead is also continuing, with these two projects expected to be placed System. This expansion, which is the ﬁnal component of the Company’s into service in 2017 and 2018, respectively. In February 2017, Eastern Access Program, provides increased access to reﬁneries the Company also announced it had acquired an effective 50% in the upper midwest United States and eastern Canada. EEP also interest in the partnership that holds the 497-MW Hohe See Offshore continued to execute on the Lakehead System Mainline Expansion Wind Project in Germany, with a targeted in-service date in 2019, through completion of additional tankage on the Southern Access increasing Enbridge’s net operating renewable power generating expansion between Superior, Wisconsin and Flanagan, Illinois. capacity to approximately 2,500 MW. Management’s Discussion & Analysis 37 The following table summarizes the status of the Company’s commercially secured projects, organized by business segment. Expenditures to date reﬂect total cumulative expenditures incurred from inception of the project to December 31, 2016. Estimated Capital Cost1 Expenditures to Date2 Expected In–Service Date Status (Canadian dollars, unless stated otherwise) Liquids Pipelines 1. Eastern Access (EEP) 3 2. Norlite Pipeline System (the Fund Group)4 3. JACOS Hangingstone Project (the Fund Group) 4. Regional Oil Sands Optimization Project (the Fund Group) 5. Bakken Pipeline System (EEP) US$0.3 billion US$0.3 billion $1.3 billion $0.2 billion $2.6 billion $0.8 billion $0.1 billion $2.2 billion US$1.5 billion No signiﬁcant expenditures to date 6. Lakehead System Mainline Expansion (EEP)3 US$0.8 billion US$0.7 billion 7. Canadian Line 3 Replacement Program (the Fund Group)5 $4.9 billion 8. U.S. Line 3 Replacement Program (EEP)3, 5 9. Sandpiper Project (EEP)6 US$2.6 billion US$2.6 billion $1.5 billion US$0.4 billion US$0.8 billion 2016 2017 2017 2017 (in phases) Complete Under construction Under construction Under construction 2017 Under construction 2016 – 2019 (in phases) 2019 2019 Application withdrawn Under construction Pre–construction Pre–construction Application withdrawn Gas Distribution 10. Greater Toronto Area Project Gas Pipelines and Processing 11. Walker Ridge Gas Gathering System 12. Big Foot Oil Pipeline 13. Eaglebine Gathering (EEP) $0.9 billion $0.9 billion 2016 Complete US$0.4 billion US$0.3 billion US$0.2 billion US$0.2 billion US$0.2 billion US$0.1 billion 2014 – TBD (in phases) TBD 2015 – TBD (in phases) 14. Heidelberg Oil Pipeline US$0.1 billion US$0.1 billion 15. Tupper Main and Tupper West Gas Plants 16. Aux Sable Extraction Plant Expansion 17. Stampede Oil Pipeline Green Power and Transmission 18. New Creek Wind Project 19. Chapman Ranch Wind Project 20. Rampion Offshore Wind Project 21. Hohe See Offshore Wind Project7 $0.5 billion US$0.1 billion US$0.2 billion $0.5 billion US$0.1 billion US$0.1 billion US$0.2 billion US$0.4 billion $0.8 billion (£0.37 billion) US$0.2 billion US$0.3 billion $0.4 billion (£0.20 billion) $1.7 billion (€1.07 billion) No signiﬁcant expenditures to date 2016 2016 2016 2018 2016 2017 2018 2019 Complete Complete Complete (Phase 1) Complete Acquisition completed Complete Under construction Complete Under construction Under construction 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, 2016. 3 The Eastern Access and Lakehead System Mainline Expansion projects are funded 75% by Enbridge and 25% by EEP. As discussed under L3R Program below, following EEP's January 27, 2017 announcement, the U.S. L3R Program is being funded 99% by Enbridge and 1% by EEP. EEP also increased its joint funding in Eastern Access by 15%. 4 Enbridge will construct and operate Norlite. Keyera Corp. will fund 30% of the project. 5 As discussed under L3R Program below, the expected cost and in-service date of this project is under review by the Company in light of the schedule for regulatory review and approval communicated by the MNPUC on October 28, 2016. 6 The Company planned to construct and operate the Sandpiper Project with MPC funding 37.5% of the project. However, on October 28, 2016, the MNPUC approved EEP’s application to withdraw the Sandpiper Projects regulatory applications without conditions. 7 In February 2017, Enbridge acquired an effective 50% interest in the Hohe See Offshore Wind Project Risks related to the development and completion of growth projects are described under Risk Management and Financial Instruments – General Business Risks. 38 Enbridge Inc. 2016 Annual Report Norman Norman Wells Wells CA NA DA Zama Zama Fort McMurray Fort McMurray Cheecham Cheecham Edmonton Edmonton Hardisty Hardisty 7 Blaine Blaine Portland Portland Fort McMurray Fort McMurray 3 Cheecham Cheecham Edmonton Edmonton 2 4 Hardisty Hardisty Minot Clearbrook Clearbrook 9 8 Superior Superior Montreal Montreal UNITED STA TE S UNITED STATE S OF AMERICA OF AMERICA 5 6 1 Buffalo Buffalo Chicago Chicago Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Patoka Patoka Cushing Cushing M E X I C Houston Houston New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans Liquids Pipelines 1 Eastern Access (EEP) 2 Norlite Pipeline System (the Fund Group) 3 JACOS Hangingstone Project (the Fund Group) 4 Regional Oil Sands Optimization Project (the Fund Group) 5 Bakken Pipeline System (EEP) 6 Lakehead System Mainline Expansion (EEP) 7 Canadian Line 3 Replacement Program (the Fund Group) 8 U.S. Line 3 Replacement Program (EEP) 9 Sandpiper Project (EEP) Assets in Operation Growth Projects Application Withdrawn Management’s Discussion & Analysis 39 Liquids Pipelines Eastern Access (EEP) The Eastern Access initiative included a series of Enbridge and EEP crude oil pipeline projects to provide increased access to reﬁneries in the upper midwest United States and eastern Canada. The majority of the Canadian and United States components of the Eastern Access initiative were completed between 2013 and 2015. The remaining component of the Eastern Access initiative involved a further upsizing of EEP’s Line 6B. The Line 6B capacity expansion from Griffith, Indiana to Stockbridge, Michigan increased capacity from 500,000 bpd to 570,000 bpd and included pump station modiﬁcations at the Griffith, Niles and Mendon stations, additional modiﬁcations at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. This expansion was placed into service in June 2016 at a total cost of approximately US$0.3 billion. The Eastern Access projects undertaken by EEP were funded 75% by Enbridge and 25% by EEP. On January 27, 2017, EEP exercised its option to acquire an additional 15% economic interest in the Eastern Access projects at a book value of approximately US$360 million. In July 2015, Enbridge and EEP reached an agreement to forego distributions to Enbridge Energy, Limited Partnership (EELP) for its interests in the Eastern Access projects until the second quarter of 2016. EELP holds partnership interests in assets that are jointly funded by Enbridge and EEP, including the Eastern Access projects. In return, until the second quarter of 2016, Enbridge’s capital funding contribution requirements to the Eastern Access projects were offset against its foregone cash distribution. Norlite Pipeline System (the Fund Group) The Company is undertaking the development of Norlite, a new industry diluent pipeline originating from Edmonton, Alberta to meet the needs of multiple producers in the Athabasca oil sands region. The scope of the project was increased to a 24-inch diameter pipeline and based on current engineering design, will provide an initial capacity of approximately 218,000 bpd of diluent, with the potential to be further expanded to approximately 465,000 bpd of capacity with the addition of pump stations. Norlite will be anchored by throughput commitments from Suncor Energy Inc., Total E&P Canada Ltd. and Teck Resources Limited (Fort Hills Partners) for production from the proposed Fort Hills Partners’ oil sands project (Fort Hills Project) and from Suncor Energy Oil Sands Limited Partnership’s (Suncor Partnership) proprietary oil sands production. Norlite will involve the construction of a new 449-kilometre (278-mile) pipeline from the Company’s Stonefell Terminal to its Cheecham Terminal with an extension to Suncor Partnership’s East Tank Farm, which is adjacent to the Company’s existing Athabasca Terminal. Under an agreement with Keyera, Norlite has the right to access certain existing capacity on Keyera’s pipelines between Edmonton, Alberta and Stonefell, Alberta and, in exchange, Keyera has elected to participate in the new pipeline infrastructure project as a 30% non-operating owner. Norlite is expected to be completed in the second quarter of 2017 at an estimated cost of approximately $1.3 billion, with expenditures to date of approximately $0.8 billion. JACOS Hangingstone Project (the Fund Group) The Company is undertaking the construction of facilities and it will provide transportation services to the Japan Canada Oil Sands Limited (JACOS) Hangingstone Oil Sands Project (JACOS Hangingstone). JACOS and Nexen Energy ULC, a wholly-owned subsidiary of China National Offshore Oil Corporation Limited, are partners in the project which is operated by JACOS. The Company is constructing a new 53-kilometre (33-mile), 12-inch lateral pipeline to connect the JACOS Hangingstone project site to the Company’s existing Cheecham Terminal. The project, which will provide capacity of 40,000 bpd, has been delayed at the shippers’ request and is targeted to enter service in the third quarter of 2017. The estimated cost of the project is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion. Regional Oil Sands Optimization Project (the Fund Group) As part of the Regional Oil Sands Optimization project, in January 2017 the Company completed the twinning of the southern section of the Athabasca Pipeline with a 36-inch diameter pipeline from Kirby Lake, Alberta to the crude oil hub at Hardisty, Alberta. The initial capacity of the Athabasca Pipeline Twin is 450,000 bpd and it can be further expanded in the future to 800,000 bpd through additional pumping horsepower. The Regional Oil Sands Optimization project also involves the upsize of a 100-kilometre (60-mile) segment of the Wood Buffalo Extension between Cheecham, Alberta and Kirby Lake, Alberta from a 30-inch diameter pipeline to a 36-inch diameter pipeline, which will connect to the origin of the Athabasca Pipeline Twin at Kirby Lake, Alberta. This component of the project is now expected to be in service in December 2017 to align with the primary shipper’s production proﬁle. The estimated total cost of the Regional Oil Sands Optimization Project is approximately $2.6 billion, with expenditures to date of approximately $2.2 billion. The integrated Wood Buffalo Extension and Athabasca Pipeline Twin will transport diluted bitumen from the proposed Fort Hills Project in northeastern Alberta, as well as from oil sands production from the Suncor Partnership in the Athabasca region. The Athabasca Pipeline Twin portion of the project, after being placed into service in January 2017, is also shipping blended bitumen from the Cenovus Christina Lake Steam Assisted Gravity Drainage project near the origin of the Athabasca Pipeline Twin. Bakken Pipeline System (EEP) In August 2016, Enbridge and EEP announced that EEP had entered into an agreement with MPC to form a new joint venture, MarEn Bakken Company LLC, which in turn has entered into an agreement to acquire a 49% equity interest in the holding company that owns 75% of the Bakken Pipeline System from an affiliate of Energy Transfer Partners, L.P. and Sunoco Logistics Partners, L.P. Under this arrangement, EEP and MPC would indirectly hold 75% and 25% interests, respectively, of the joint venture’s 49% interest in the holding company of the Bakken Pipeline System. This transaction was closed on February 15, 2017. The purchase price of EEP’s effective 27.6% interest in the Bakken Pipeline System is US$1.5 billion. 40 Enbridge Inc. 2016 Annual Report EEP will fund the US$1.5 billion acquisition through a bridge loan system optimization actions have been undertaken to substantially provided by Enbridge through one of its affiliates. The bridge loan will mitigate any impact on throughput associated with any delays remain in place until a joint funding arrangement with Enbridge and in obtaining this amendment. its affiliates is ﬁnalized. A special committee of independent directors of the board of Enbridge Management has been established that would establish a joint funding arrangement for this investment. This arrangement, which is expected to be ﬁnalized in the second quarter of 2017, remains subject to the review of the conﬂicts committee of the Board of EEP’s General Partner (GP). The remaining scope of the Lakehead System Mainline Expansion includes the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois. Included therein was additional tankage of approximately US$0.4 billion which was completed on various dates between the third quarter of 2015 and the third quarter of 2016. In addition, the expansion to increase the pipeline The Bakken Pipeline System connects the proliﬁc Bakken formation capacity to 1,200,000 bpd requires only the addition of pumping in North Dakota to markets in eastern PADD II and the United States horsepower with no pipeline construction and is expected to cost Gulf Coast, providing customers with access to premium markets approximately US$0.4 billion. In conjunction with shippers, a decision at a competitive cost. The Bakken Pipeline System consists of the was made to delay the in-service date of this phase of the Southern Dakota Access Pipeline and the Energy Transfer Crude Oil Pipeline Access expansion to 2019 to align more closely with the anticipated projects. The Dakota Access Pipeline consists of 1,886 kilometres in-service date for the U.S. L3R Program. The expenditures incurred (1,172 miles) of 30-inch pipeline from the Bakken/Three Forks to date are approximately US$0.7 billion. production area in North Dakota to Patoka, Illinois. It is expected to initially deliver in excess of 470,000 bpd of crude oil and has the potential to be expanded to 570,000 bpd. The Energy Transfer Crude Oil Pipeline consists of 100 kilometres (62 miles) of new 30-inch diameter pipe, 1,104 kilometres (686 miles) of converted 30-inch diameter pipe, and 64 kilometres (40 miles) of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas. Lakehead System Mainline Expansion (EEP) The Lakehead System Mainline Expansion includes several projects to expand capacity of the Lakehead System mainline between its origin at the Canada/United States border, near Neche, North Dakota, and Flanagan, Illinois. These projects are in addition to expansions of the Lakehead System mainline being undertaken as part of the Eastern Access initiative and include the expansion of Alberta Clipper (Line 67) and Southern Access (Line 61) and the construction of the Spearhead North Twin pipeline (Line 78). The expansion of Line 67 and construction of Line 78 were completed in 2015. The Line 67 pipeline capacity expansion remains subject to the receipt of an amendment to the current Presidential Permit to allow for operation of the Line 67 pipeline at the United States/Canada border at its currently planned operating capacity of 800,000 bpd. On February 10, 2017, the United States Department of State (Department), the agency that is responsible for issuing permits for cross-border pipelines pursuant to a delegation of authority by the President under an Executive Order, issued a Draft Supplemental EEP will operate the project on a cost-of-service basis. The Lakehead System Mainline Expansion is funded 75% by Enbridge and 25% by EEP. EEP has the option to increase its economic interest held by up to an additional 15% at cost. In July 2015, Enbridge and EEP reached an agreement to forego distributions to EELP for its interests in the Lakehead System Mainline Expansion until the second quarter of 2016. EELP holds partnership interests in assets that are jointly funded by Enbridge and EEP, including the Lakehead System Mainline Expansion. In return, until the second quarter of 2016, Enbridge’s capital funding contribution requirements to the Lakehead System Mainline Expansion were offset against its foregone cash distribution. Line 3 Replacement Program In 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. The L3R Program will support the safety and operational reliability of the mainline system, enhance ﬂexibility, allow the Company and EEP to optimize throughput on the mainline system and restore approximately 370,000 bpd of capacity from western Canada into Superior, Wisconsin. Canadian Line 3 Replacement Program (the Fund Group) The Canadian L3R Program will complement existing integrity programs by replacing approximately 1,084 kilometres (673 miles) of the remaining line segments of the existing Line 3 pipeline between Hardisty, Alberta and Gretna, Manitoba. In April 2016, the NEB found that the Canadian L3R Program Environmental Impact Statement (Draft SEIS), which determined that is in the Canadian public interest and issued ﬁnal conditions and there were no signiﬁcant adverse environmental impacts from the a recommendation to the Federal Cabinet to issue the Certiﬁcate planned capacity increase. Upon closure of a public comment period of Public Convenience and Necessity (the Certiﬁcate) for the on the Draft SEIS, which is currently scheduled for March 27, 2017, construction and operation of the pipeline and related facilities. the Department will review all received comments and prepare a Final A decision by the Federal Cabinet was expected to be issued SEIS. The Executive Order also requires that the Department initiate three months following the NEB recommendation per legislation. a 90-day inter-agency consultation period to solicit comments from However, because of the Federal Government’s January 27, 2016 certain other federal agencies on whether the Line 67 expansion announcement that, outside of the NEB process it had directed will serve the “national interest.” Following issuance of the Final SEIS Federal agencies to conduct an assessment of direct and upstream and completion of the inter-agency consultation process, GHG emissions and incremental consultation with affected the Administration will make a decision and issue a Presidential communities and Indigenous peoples, the Minister of Natural Permit if it ﬁnds that doing so is in the national interest. This is Resources sought an extension of four months to the Government’s expected later in the year and meanwhile, a number of temporary legislated decision-making time limit (to seven months in total). Management’s Discussion & Analysis 41 Regulatory approval was received from the Government of Canada United States Line 3 Replacement Program (EEP) on November 29, 2016 with no material changes to permit conditions and on December 1, 2016, the NEB issued the Certiﬁcate. Once the Certiﬁcate was issued, Natural Resources Canada released the ﬁnal assessment of the upstream GHG emissions, as well as reports summarizing the additional Crown Consultation The U.S. L3R Program will complement existing integrity programs by replacing approximately 576 kilometres (358 miles) of the remaining line segments of the existing Line 3 pipeline between Neche, North Dakota and Superior, Wisconsin. with Indigenous groups and the public online survey conducted EEP is in the process of obtaining the appropriate permits for by Natural Resources Canada. The report assessing the upstream GHG emissions estimates that the upstream GHG emissions in Canada associated with the production and processing of crude oil transported by the Canadian L3R Program, based on a capacity of 760,000 bpd, could be between 19 and 26 megatonnes of carbon dioxide equivalent per year. The report also found that the estimated emissions are not constructing the U.S. L3R Program in Minnesota. The project requires both a Certiﬁcate of Need and an approval of the pipeline’s route (Route Permit) from the MNPUC. The MNPUC found both the Certiﬁcate of Need and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. With respect to the Route Permit, the Minnesota Department of Commerce (DOC) held public scoping meetings in August 2015. necessarily incremental; the degree to which the estimated emissions On February 1, 2016, the MNPUC issued a written order would be incremental depends on the expected price of oil, the (the U.S. L3R Order) joining the Line 3 Certiﬁcate of Need and availability and costs of other transportation modes, such as crude Route Permit dockets, requiring the DOC to prepare a ﬁnal by rail, and whether other pipeline projects are built. The Crown Environmental Impact Statement (EIS) before Certiﬁcate of Need Consultation report concluded that the NEB recommended and Route Permit processes commence, and sent the cases conditions along with the commitments made by Enbridge are to the Office of Administrative Hearings with direction to re-start responsive to, and reasonably accommodate the project speciﬁc the process. On February 5, 2016, EEP ﬁled a Petition for concerns raised by Indigenous groups and that other concerns Reconsideration of the requirement to provide a ﬁnal EIS ahead will be addressed by the Government’s commitment to modernize of the commencement of the Certiﬁcate of Need and Route Permit the NEB and to review the environmental assessment legislation. proceedings noted in the U.S. L3R Order. At a hearing held on The report summarizing the online survey states that 3,170 submissions March 24, 2016, the MNPUC denied the Petition for Reconsideration. were received in response to the questionnaire including from both individuals directly affected by the project, as well as general members of the public, and the report concluded that the majority of concerns centered around issues dealt with by the NEB including soil and ground water contamination and impact to farmers and nearby communities. With the issuance of the Environmental Assessment Worksheet (EAW) on April 11, 2016, the MNPUC commenced the EIS process. Consultation regarding the EAW, which deﬁnes the scope of the EIS, commenced with a series of public meetings in communities in Minnesota on April 25, 2016, which concluded on May 13, 2016. The DOC addressed the comments received on the draft EIS In December 2016, the Manitoba Metis Federation and the Association scope and issued its scoping recommendations to the MNPUC of Manitoba Chiefs applied to the Federal Court of Appeal (Federal on September 22, 2016. Court) for leave to judicially review the Government of Canada’s decision to approve the Canadian L3R Program. The outcome or timing of these proceedings, including their potential impact upon the Canadian L3R Program cannot be predicted at this time. Three external parties ﬁled motions requesting that the scoping process be re-opened or that a comment period be established because of the issuance of the Consent Decree settling the Line 6B pipeline crude oil release in Marshall, Michigan and the withdrawal Subject to regulatory and other approvals, the Canadian L3R Program of regulatory applications pending with the MNPUC with respect is targeted to be completed in 2019 at an estimated capital cost of to the Sandpiper Project discussed below. EEP ﬁled a reply approximately $4.9 billion, with expenditures to date of approximately challenging the need to re-open the scoping process indicating $1.5 billion. With a delay in construction arising from a longer than that neither of these events warrants further extension of time. anticipated permitting process, the cost of this project is expected The motions ﬁled by the external parties were considered and to increase. Also, in view of the MNPUC’s decision in respect of the denied by the MNPUC at a hearing held on October 28, 2016. schedule for the remainder of the regulatory approval process for the U.S. L3R Program, as discussed in United States Line 3 Replacement Program (EEP) below, the Company is reviewing the expected impact on the Canadian L3R Program’s schedule and cost estimates. It is possible that the in-service date could be delayed, at least until later in 2019. Costs of the Canadian L3R Program will be recovered through a 15-year toll surcharge mechanism under the CTS. At the hearing on October 28, 2016, the MNPUC also approved the scope of the EIS. The MNPUC’s decision was conﬁrmed in a written order on November 30, 2016. The DOC published the EIS Public Notice on December 5, 2016, which provided greater clarity with respect to the timeline for the regulatory approval of the U.S. L3R Program in Minnesota. On December 20, 2016, two intervenors ﬁled petitions for reconsideration of the MNPUC's November 30, 2016 order. EEP ﬁled a response on January 3, 2017. The MNPUC denied the petitions at a hearing which took place on February 9, 2017. EEP is currently evaluating the impact of the MNPUC’s November 30, 2016 order on the cost and in-service date of this project. It is possible, under the schedule approved by the MNPUC, that the in-service date could be delayed, at least until later in 2019. 42 Enbridge Inc. 2016 Annual Report On January 27, 2017, Enbridge and EEP entered into an agreement for the joint funding of the U.S. L3R Program, whereby Enbridge and EEP will fund 99% and 1%, respectively, of the project cost. Enbridge has reimbursed EEP approximately US$450 million for expenditures incurred to date on the project and it will fund 99% of the capital costs through construction. EEP has the option to increase its economic interest by up to 40% at book value until four years after the project is placed into service. EEP will recover the costs based on its existing Facilities Surcharge Mechanism with the initial term of the agreement being 15 years. For the purpose of the toll surcharge, the agreement speciﬁes a 30-year recovery of the capital based on a cost-of-service methodology. Sandpiper Project (EEP) The Sandpiper Project was part of the Light Oil Market Access Program initiative and would have expanded and extended EEP’s North Dakota feeder system. The Bakken takeaway capacity of the North Dakota System would have been expanded by 225,000 bpd to a total of 580,000 bpd. The proposed expansion involved construction of a 965-kilometre (600-mile) line from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line would have twinned the existing 210,000 bpd North Dakota System mainline, which now terminates at Clearbrook Terminal in Minnesota, by adding 250,000 bpd of capacity between Tioga and Berthold, North Dakota and 225,000 bpd of capacity between Berthold and Clearbrook, both with new 24-inch diameter pipelines, as well as adding 375,000 bpd of capacity between Clearbrook and Superior with a new 30-inch diameter pipeline. On September 1, 2016, EEP announced that it applied for the withdrawal of regulatory applications for the Sandpiper Project pending with the MNPUC because EEP concluded that the project should be delayed until such time as crude oil production in North Dakota recovers sufficiently to support development of new pipeline capacity. Based on updated projections, EEP expects that this pipeline capacity will not likely be needed until beyond its current ﬁve-year planning horizon. On October 28, 2016, the MNPUC approved EEP’s application to withdraw the regulatory applications without conditions and issued the written order on November 10, 2016. In connection with the above announcement and other factors, EEP also evaluated the Sandpiper Project for impairment and determined that the project was impaired. In the third quarter of 2016, EEP recorded an asset impairment of US$763 million, including related project costs. Of the total amount, US$270 million was allocated to MPC, EEP’s partner in the Sandpiper Project, and US$493 million was attributable to EEP’s. unitholders. The Company’s Consolidated Statements of Earnings for the year ended December 31, 2016 includes a gross charge, including additional project costs incurred in the fourth quarter, of $1,004 million, of which $875 million was attributable to noncontrolling interests in EEP and MPC and $81 million- after tax attributable to Enbridge’s common shareholders. Gas Distribution Greater Toronto Area (GTA) Project EGD undertook the expansion of its natural gas distribution system in the GTA to meet the demands of growth and to continue the safe and reliable delivery of natural gas to current and future customers. The GTA project involved the construction of two new segments of pipeline, a 27-kilometre (17-mile), 42-inch diameter pipeline (Western segment) and a 23-kilometre (14-mile), 36-inch diameter pipeline (Eastern segment) as well as related facilities to upgrade the existing distribution system that delivers natural gas to several municipalities in the GTA. Both the Western and Eastern segments were placed into service in March 2016. The total project cost was approximately $0.9 billion. Toledo Ottawa 10 Toronto Sarnia Buffalo Gas Distribution 10 Greater Toronto Area Project Management’s Discussion & Analysis 43 Gas Pipelines and Processing Walker Ridge Gas Gathering System The Company has agreements with Chevron USA Inc. (Chevron) and several other producers, to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, the Company constructed and owns and operates the WRGGS to provide natural gas gathering services to the Chevron operated Jack St. Malo and Big Foot ultra-deep water developments. The WRGGS includes 274 kilometres (170 miles) of 8-inch or 10-inch diameter pipeline at depths of up to approximately 2,150 metres (7,000 feet), with capacity of 100 mmcf/d. The Jack St. Malo portion of the WRGGS was placed into service in December 2014. The Big Foot Gas Pipeline portion of the WRGGS has been installed on the sea ﬂoor and is awaiting Big Foot platform installation, which has been delayed due to installation problems experienced by Chevron. Chevron continues to assess the extent of the delay. Notwithstanding the Big Foot platform installation delay, the Company began collecting certain fees speciﬁed in the transportation services agreements effective the fourth quarter of 2015. The total WRGGS project is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.3 billion. Big Foot Oil Pipeline Under agreements with Chevron, Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc., the Company completed the installation on the sea ﬂoor of a 64-kilometre (40-mile), 20-inch oil pipeline with a capacity of 100,000 bpd from Chevron’s Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil pipeline project is complementary to the Company’s undertaking of the WRGGS construction, discussed above. Upon completion of the project, the Company will operate the Big Foot Pipeline, located approximately 274 kilometres (170 miles) south of the coast of Louisiana. As noted above, although the Big Foot ultra-deep water development has been delayed, the Company began collecting certain fees in the fourth quarter of 2015. The estimated capital cost of the project is approximately US$0.2 billion, with expenditures to date of approximately US$0.2 billion. Eaglebine Gathering (EEP) In 2015, EEP and MEP announced their entry into the emerging Eaglebine shale play in East Texas through two transactions totalling approximately US$0.2 billion. One of the transactions involved MEP acquiring New Gulf Resources, LLC’s midstream business in Leon, Madison and Grimes Counties, Texas. The acquisition was completed in 2015 and consisted of a natural gas gathering system that is currently in operation. In 2015, EEP and MEP also completed construction of the Ghost Chili pipeline project, which consisted of a lateral and associated facilities that created gathering capacity of over 50 mmcf/d for rich natural gas to be delivered from Eaglebine production areas to their complex of cryogenic processing facilities in East Texas. As part of Phase I, the initial facilities were placed into service in October 2015. EEP also expects to construct the Ghost Chili Extension Lateral to fully utilize the gathering capacity with the rest of EEP’s processing assets when additional development in the basin supports it. Given the proximity of EEP’s existing East Texas assets, this expansion into Eaglebine will allow EEP to offer gathering and processing services while leveraging assets on its existing footprint. Expenditures incurred to date are approximately US$0.1 billion. Heidelberg Oil Pipeline The Company constructed and owns and operates a crude oil pipeline in the Gulf of Mexico which connects the Heidelberg development, operated by Anadarko Petroleum Corporation, to an existing third party system. Heidelberg Pipeline, a 58-kilometre (36-mile), 20-inch diameter pipeline with capacity of 100,000 bpd, originates in Green Canyon Block 860, approximately 320 kilometres (200 miles) southwest of New Orleans, Louisiana at an estimated depth of 1,600 metres (5,300 feet). Heidelberg Pipeline was placed into service in January 2016 at an approximate cost of US$0.1 billion. Tupper Main and Tupper West Gas Plants In April 2016, Enbridge completed the acquisition of the Tupper Plants and associated pipelines from a Canadian subsidiary of Murphy Oil Corporation for a purchase price of approximately $0.5 billion. The Tupper Plants have a combined total licensed capacity of 320 million cubic feet per day and are located within the Montney gas play, 35 kilometres (22 miles) southwest of Dawson Creek, British Columbia, adjacent to Enbridge’s existing Sexsmith gathering system and close to the Alliance Pipeline, which is 50% owned by the Fund Group. These assets, including 53 kilometres (33 miles) of high pressure pipelines, are currently in operation and are underpinned by long-term take-or-pay contracts. Aux Sable Extraction Plant Expansion In September 2016, the Company completed the expansion of fractionation capacity and related facilities at the Aux Sable extraction and fractionation plant located in Channahon, Illinois. The expansion provides approximately 24,500 bpd of incremental fractionation capacity and will serve the growing NGL-rich gas stream on the Alliance Pipeline, allow for effective management of Alliance Pipeline’s downstream natural gas heat content and support additional production and sale of NGL products. The Company’s share of the project cost was approximately US$0.1 billion. Stampede Oil Pipeline In 2015, Enbridge announced that it will build, own and operate a crude oil pipeline in the Gulf of Mexico to connect the planned Stampede development, which is operated by Hess Corporation, to an existing third party pipeline system. The Stampede Pipeline, a 26-kilometre (16-mile), 18-inch diameter pipeline with capacity of approximately 100,000 bpd, will originate in Green Canyon Block 468, approximately 350 kilometres (220 miles) southwest of New Orleans, Louisiana, at an estimated depth of 1,200 metres (3,900 feet). Stampede Pipeline is expected to be completed at an approximate cost of US$0.2 billion and is expected to be placed into service in 2018. Expenditures incurred to date are approximately US$0.1 billion. 44 Enbridge Inc. 2016 Annual Report 15 C ANA DA Calgary Calgary Superior Superior Montreal Montreal UNITED STA TE S UNITED STA TE S OF AMERIC A OF AMERIC A Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago 16 Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Cushing Cushing M E X I C 0 13 Houston Houston New Orleans New Orleans Gas Pipelines and Processing 11 Walker Ridge Gas Gathering System 15 Tupper Main and Tupper West Gas Plants 12 Big Foot Oil Pipeline 16 Aux Sable Extraction Plant Expansion 13 Eaglebine Gathering (EEP) 17 Stampede Oil Pipeline 14 Heidelberg Oil Pipeline Assets in Operation Growth Projects Gas Plants in Operation Management’s Discussion & Analysis 45 Green Power and Transmission New Creek Wind Project In 2015, Enbridge announced it had acquired a 100% interest in the 103-MW New Creek Wind Project, located in Grant County, West Virginia, from EverPower Wind Holdings, LLC. The project comprised 49 Gamesa turbines and it entered service in December 2016. The New Creek Wind Project was constructed under a ﬁxed-price engineering, procurement and construction agreement, with White Construction Inc. at a total cost of approximately US$0.2 billion. Gamesa is providing turbine operations and maintenance services under a ﬁve-year ﬁxed price contract. The project was backed by medium and long-term power offtake agreements, as well as renewable energy credit sales. Chapman Ranch Wind Project On September 9, 2016, Enbridge acquired a 100% interest in the 249-MW Chapman Ranch Wind Project, located in Nueces County, Texas, from Apex Clean Energy Holdings, LLC. Enbridge’s total investment is expected to be approximately US$0.4 billion, with expenditures incurred to date of approximately US$0.3 billion. The Chapman Ranch Wind Project will consist of 81 Acciona Windpower North America, LLC (Acciona) turbines and is expected to be in service in the third quarter of 2017. The project is being constructed under a ﬁxed-price engineering, procurement and construction agreement, with Renewable Energy Systems America Inc. Hohe See Offshore Wind Project On February 17, 2017, the Company announced it had acquired an effective 50% interest in the partnership that will construct the 497-MW Hohe See Offshore Wind Project. Enbridge will partner with state-owned German utility EnBW in the construction and operation of this late-design project, with the target in-service date of 2019. The Hohe See Offshore Wind Project is located in the North Sea, 98 kilometres (61 miles) off the coast of Germany and will be constructed under ﬁxed-price engineering, procurement, construction and installation contracts, which have been secured with key suppliers. The Hohe See Offshore Wind Project is backed by a government legislated 20-year revenue support mechanism. Enbridge’s total investment in this project through the project’s completion and in-service date in 2019 is expected to be approximately $1.7 billion (€1.07 billion), including planned spend of approximately $0.6 billion (€0.44 billion) throughout 2017. Other Announced Projects Under Development The following projects have been announced by the Company, but have not yet met the Company’s criteria to be classiﬁed as commercially secured. The Company also has additional projects under development that have not yet progressed to the point of public announcement. Acciona will provide turbine operations and maintenance services Liquids Pipelines under a ﬁve-year ﬁxed-price contract with an option to extend. The project is backed by a 12-year power offtake agreement. Northern Gateway Project Rampion Offshore Wind Project Northern Gateway involved constructing a twin 1,178-kilometre (731-mile) pipeline system from near Edmonton, Alberta to a new In 2015, Enbridge announced the acquisition of a 24.9% interest marine terminal in Kitimat, British Columbia. One pipeline would in the 400-MW Rampion Project in the United Kingdom, located transport crude oil for export from the Edmonton area to Kitimat and 13 kilometres (8 miles) off the Sussex coast in the United Kingdom was proposed to be a 36-inch diameter line with an initial capacity of at its nearest point. The Company’s total investment in the project 525,000 bpd. The other pipeline would be used to transport imported through construction is expected to be approximately $0.8 billion condensate from Kitimat to the Edmonton area and was proposed (£0.37 billion). The Rampion Project was developed and is being to be a 20-inch diameter line with an initial capacity of 193,000 bpd. constructed by E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE. Construction of the wind farm began in September 2015 and it is expected to be fully operational in 2018. The Rampion Project is backed by revenues from the United Kingdom’s ﬁxed price Renewable Obligation certiﬁcates program and a 15-year PPA. In 2010, Northern Gateway submitted an application to the Joint Review Panel (JRP) which had a broad mandate to assess the potential environmental effects of the project and to determine if development of Northern Gateway was in the public interest. Under the terms of the agreement, Enbridge became one of the three shareholders in Rampion Offshore Wind Limited which owns In December 2013, the JRP issued its report on Northern Gateway. The report found that the petroleum industry is a signiﬁcant driver the Rampion Project with the United Kingdom’s Green Investment of the Canadian economy and an important contributor to the Bank plc holding a 25% interest and E.ON SE retaining the Canadian standard of living and noted that the beneﬁts of Northern balance of 50.1% interest. Enbridge has incurred costs to date Gateway outweigh its burdens and that “Canadians would be better of approximately $0.4 billion (£0.20 billion). off with the Enbridge Northern Gateway Project than without it.” 46 Enbridge Inc. 2016 Annual Report North Sea UNITED KINGDOM London Brighton and Hove Amsterdam THE NETHERLANDS Brussels Cologne English Channel FRANCE BELGIUM GERMANY CA NA DA Calgary Superior Superior Montreal Montreal UNITED STAT ES UNITED STAT ES OF AMERIC A OF AMERIC A Denver Denver Las Vegas Las Vegas Sarnia Sarnia Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo 18 Cushing Cushing M E X I C 0 Houston Houston 19 Green Power and Transmission 18 New Creek Wind Project 19 Chapman Ranch Wind Project 20 Rampion Offshore Wind Project 21 Hohe See Offshore Wind Project Power Transmission in Operation Wind Assets in Operation Solar Assets in Operation Growth Projects—Wind Management’s Discussion & Analysis 47 In June 2014, the Governor in Council (GIC) approved Northern The Federal Government chose not to re-do the Crown consultation. Gateway, subject to 209 conditions. Nine applications to the Federal By way of an Order in Council dated November 25, 2016, the GIC Court for leave for judicial review of the Order in Council approving directed the NEB to dismiss Northern Gateway’s application for the the project were ﬁled in July 2014. The applicants made two basic Certiﬁcates. On December 6, 2016, the NEB issued orders rescinding arguments in seeking leave. First, they argued that the JRP report the Certiﬁcates, thereby effectively cancelling the project. 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. In consultation with the potential shippers and Aboriginal equity partners, the Company has assessed the Federal Government’s decision and concluded that Northern Gateway cannot proceed as envisioned. Project activity is limited to winding down while evaluating The decision of the Federal Court was released on June 30, 2016. potential value preservation options. Total expenditures incurred The Federal Court found that for the most part the environmental to date on the project are approximately $656 million. After taking review and Aboriginal consultation processes were reasonable, and into consideration the amount recoverable from potential shippers the legal challenges to those aspects of the process were dismissed. on Northern Gateway, the Company reﬂected an impairment However, the Federal Court found the Phase IV Crown consultation of $373 million ($272 million after-tax) in the fourth quarter of 2016 process undertaken by the Federal Government was unacceptably within the Liquids Pipelines segment. ﬂawed, and for that reason it quashed the Certiﬁcates and sent the matter back to the GIC for redetermination. The Federal Court indicated that the GIC had three options available Green Power and Transmission Éolien Maritime France SAS on redetermination: it could redo the Phase IV Crown consultation Effective May 19, 2016, Enbridge acquired a 50% interest in EMF, and then direct the NEB to issue the Certiﬁcates, it could direct a French offshore wind development company. EMF is co-owned the NEB to dismiss the application for the Certiﬁcates, or it could by Enbridge and EDF Energies Nouvelles, a subsidiary of Électricité ask the NEB to reconsider its recommendations. de France S.A. EMF holds licenses for three large-scale offshore Neither Northern Gateway nor the Federal Government sought leave to appeal to the Supreme Court of Canada. wind farms off the coast of France that would produce a combined 1,428 MW of power. The development of these projects is subject to ﬁnal investment decision and regulatory approvals, the timing of which is not yet certain. Enbridge’s portion of the costs incurred to date is approximately $194 million (€136 million). 48 Enbridge Inc. 2016 Annual Report Liquids Pipelines Earnings Before Interest and Income Taxes (millions of Canadian dollars) Canadian Mainline Lakehead System Regional Oil Sands System Mid-Continent and Gulf Coast Southern Lights Pipeline Bakken System Feeder Pipelines and Other Adjusted earnings before interest and income taxes Canadian Mainline – changes in unrealized derivative fair value gains/(loss) Canadian Mainline – Line 9B costs incurred during reversal Lakehead System – changes in unrealized derivative fair value gains/(loss) Lakehead System – hydrostatic testing Lakehead System – leak remediation costs, net of leak insurance recovery Regional Oil Sands System – northeastern Alberta wildﬁres pipelines and facilities restart costs Regional Oil Sands System – make-up rights adjustment Regional Oil Sands System – leak remediation and long- term pipeline stabilization costs, net of leak insurance recoveries Regional Oil Sands System – loss on disposal of non-core assets Regional Oil Sands System – prior period adjustment Mid-Continent and Gulf Coast – changes in unrealized derivative fair value gains/(loss) Mid-Continent and Gulf Coast – make-up rights adjustment Southern Lights Pipeline – changes in unrealized derivative fair value gains/(loss) Bakken System – Sandpiper asset impairment Bakken System – asset impairment Bakken System – changes in unrealized derivative fair value gains/(loss) Bakken System – make-up rights adjustment Feeder Pipelines and Other – gain on sale of South Prairie Region assets Feeder Pipelines and Other – Northern Gateway asset impairment loss Feeder Pipelines and Other – Eddystone Rail impairment loss Feeder Pipelines and Other – gain on sale of non-core assets Feeder Pipelines and Other – derecognition of regulatory balances Feeder Pipelines and Other – make-up rights adjustment Feeder Pipelines and Other – project development costs Feeder Pipelines and Other – changes in unrealized derivative fair value loss 2016 2015 2014 931 1,425 384 656 168 198 196 3,958 467 – (6) 15 3 (47) (32) 5 – – (2) (97) 19 (1,004) – (4) 2 850 (373) (184) – (6) (2) (5) – 896 1,108 341 516 155 213 155 3,384 (1,390) (3) (10) (72) – – 9 26 (9) 21 (7) (54) (87) – (86) (5) 8 – – – 91 – (6) (3) (1) 663 836 301 319 121 233 119 2,592 (499) (5) 8 – (97) – 8 5 – – 4 (41) 3 – – 4 (3) – – – – – 5 (4) – Earnings before interest and income taxes 3,557 1,806 1,980 Management’s Discussion & Analysis 49 Liquids Pipelines adjusted EBIT was $3,958 million in 2016 compared with adjusted EBIT of $3,384 million in 2015 and $2,592 million in 2014. The Company continued to realize growth on the Canadian Mainline, Lakehead System and Regional Oil Sands System primarily due to higher throughput that resulted from strong oil sands production in western Canada enabled by pipeline capacity expansion projects placed into service in 2015 and 2014. However, the positive effect of increased capacity on liquids pipelines throughput was substantially negated in the second quarter by the impact of extreme wildﬁres in northeastern Alberta which led to a temporary shutdown of certain of the Company’s upstream pipelines and terminal facilities resulting in a disruption of service on Enbridge’s Regional Oil Sands System with corresponding impacts on Enbridge’s downstream pipelines deliveries, including Canadian Mainline and the Lakehead System. Growth in Canadian Mainline adjusted EBIT was also affected by a combination of a lower average IJT Residual Benchmark Toll, which decreased effective April 1, 2016, and a lower foreign exchange rate on hedges used to convert United States dollar denominated toll revenue on the Canadian Mainline in 2016. The Lakehead System delivered strong operating performance driven by higher Lakehead System Local Toll, higher throughput and contributions from new assets placed into service in 2015. In 2016, the Company also beneﬁtted from stronger adjusted EBIT contributions from the United States Mid-Continent and Gulf Coast systems, attributable to increased transportation revenues mainly resulting from an increase in the level of committed take-or- pay volumes on Flanagan South. Additional details on items impacting Liquids Pipelines EBIT include: • Canadian Mainline EBIT for each year reﬂected changes in unrealized fair value gains and losses on derivative ﬁnancial instruments used to manage risk exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices. • Canadian Mainline EBIT for 2015 and 2014 included depreciation expense charged to Line 9B while it was idled and undergoing a reversal as part of the Company’s Eastern Access initiative. Liquids Pipelines (millions of Canadian dollars) 4 8 3 3 , 6 0 8 , 1 2 9 5 2 , 0 8 9 , 1 8 5 9 3 , 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 , , , , , , , , , , , , , , , 141 151 161 ■ GAAP EBIT ■■ ■■ ■ Adjusted EBIT 1 Effective January 1, 2016, the Company revised its reportable segments and reported Earnings before interest and income taxes for each reporting segment. The above information has reﬂected this change. • Lakehead System EBIT for 2016 included recoveries, as well as charges in 2015, in relation to hydrostatic testing performed on Line 2B in 2015. • Lakehead System EBIT for 2016 and 2014 included charges related to estimated costs, before insurance recoveries, associated with the Line 6B crude oil release, as well as insurance recoveries associated with the Line 6A crude oil release. • Regional Oil Sands System EBIT for each year included make-up rights adjustments. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. Generally, under such take-or-pay contracts, payments are received rateably over the life of the contract as capacity is provided, regardless of volumes shipped, and are non-refundable. Should make-up rights be utilized in future periods, costs associated with such transportation service are typically passed through to shippers, such that little or no cost is borne by Enbridge. For the purposes of adjusted EBIT, the Company reﬂects contributions from these contracts rateably over the life of the contract, consistent with contractual cash payments under the contract. • Regional Oil Sands System EBIT for each year included insurance recoveries, as well as charges in 2015 and 2014, associated with the Line 37 crude oil release which occurred in June 2013. Refer to Liquids Pipelines – Regional Oil Sands System – Line 37 Crude Oil Release. • Southern Lights Pipeline EBIT for each year reﬂected changes in unrealized fair value gains and losses on derivative ﬁnancial instruments used to manage foreign exchange risk exposure on United States dollar cash ﬂows from the Southern Lights Class A units. • Bakken System loss before interest and income taxes for 2016 reﬂected impairment charges, including related project costs, on EEP’s Sandpiper Project resulting from the withdrawal of the regulatory applications in September 2016 that were pending with the MNPUC. For additional information, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Sandpiper Project (EEP). 50 Enbridge Inc. 2016 Annual Report Liquids Pipelines Norman Norman Wells Wells NW System NW System Zama Zama Waupisoo Pipeline Waupisoo Pipeline Edmonton Edmonton Blaine Blaine Olympic Pipeline Olympic Pipeline Fort McMurray Fort McMurray Cheecham Cheecham Athabasca System Athabasca System Hardisty Hardisty C A NA DA C A NA DA Enbridge Mainline System Enbridge Mainline System Portland Portland Gretna Gretna North Dakota System North Dakota System Superior Superior Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Lakehead System Enbridge Enbridge Mainline System Mainline System Montreal Montreal UNITE D ST A T E S UNITE D ST A T E S OF AMERI CA OF AMERI CA Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Buffalo Buffalo Toledo Pipeline Toledo Pipeline Southern Access Southern Access Extension Pipeline Extension Pipeline Flanagan South and Flanagan South and Spearhead Pipeline Spearhead Pipeline Cushing Cushing Ozark Pipeline Ozark Pipeline Mustang and Mustang and Chicap Pipeline Chicap Pipeline Patoka Patoka Patoka Patoka Seaway Crude Seaway Crude Pipeline System Pipeline System M E X I C O Assets in operation Asset in operation, but held for sale as at December 31, 2016 Management’s Discussion & Analysis 51 • Bakken System EBIT for 2015 reﬂected an asset impairment charge related to EEP’s Berthold rail facility due to contracts that have not been renewed beyond 2016. • Feeder Pipelines and Other EBIT for 2016 reﬂected a gain on the sale of non-core South Prairie Region assets. • Feeder Pipelines and Other EBIT for 2016 included an asset impairment charge related to Northern Gateway. For additional information, refer to Other Announced Projects Under Development – Liquids Pipelines – Northern Gateway Project. • Feeder Pipelines and Other loss before interest and income taxes for 2016 included impairment charges related to Enbridge’s 75% joint venture interest in Eddystone Rail attributable to market conditions which impacted volumes at the rail facility. • Feeder Pipelines and Other EBIT for each year included certain business development costs related to Northern Gateway. Impact of Wildﬁres in Northeastern Alberta During the ﬁrst week of May 2016, extreme wildﬁres in northeastern Alberta resulted in the shutdown of a number of oil sands production facilities and the evacuation of more than 80,000 people from the city of Fort McMurray, which serves as a commercial and regional logistics centre for the oil sands region and a home to a signiﬁcant portion of the oil sands workforce. Enbridge’s facilities in the region were largely unaffected; however, as a precautionary measure on May 4, 2016, the Company temporarily shut down and evacuated its Cheecham terminal and curtailed operations at its Athabasca terminal. The Company also isolated and shut down pipelines in and out of the Cheecham terminal and shut down or curtailed operations on other pipelines it operates in the region. The Company coordinated with emergency response, public safety and utility officials to restore power and make any necessary repairs to its systems while working closely with producers in the region, and restarted and returned the majority of its regional pipeline systems to normal operation by the end of May 2016. Oil sands production from facilities in the vicinity of Fort McMurray, Alberta was curtailed longer given the severity and longevity of the wildﬁres, with oil sands production substantially coming back online by the end of June 2016. On average, Enbridge’s mainline system deliveries were lower by approximately 255,000 bpd during the months of May and June 2016, which represented an approximate 10% decrease in throughput compared with the throughput that the Company was delivering prior to the wildﬁres. In the third quarter of 2016, throughput on the Company’s mainline system and overall system utilization strengthened. As a result, the negative impact of reduced system deliveries on revenues impacting the Company’s adjusted EBIT and ACFFO for the second half of 2016 remained unchanged since the end of the second quarter of 2016 at approximately $74 million. The Company’s adjusted earnings and adjusted earnings per share for the year ended December 31, 2016 were reduced by $26 million and $0.03, respectively. 52 Enbridge Inc. 2016 Annual Report Canadian Mainline The mainline system is comprised of the Canadian Mainline and the Lakehead System. The Canadian Mainline is a common carrier pipeline system which transports various grades of oil and other liquid hydrocarbons within western Canada and from western Canada to the Canada/United States border near Gretna, Manitoba and Neche, North Dakota and from the United States/Canada border near Port Huron, Michigan and Sarnia, Ontario to eastern Canada and the northeastern United States. The Canadian Mainline includes six adjacent pipelines, with a combined design operating capacity of approximately 2.85 million bpd that connect with the Lakehead System at the Canada/United States border, as well as four crude oil pipelines and one reﬁned products pipeline that deliver into eastern Canada and the northeastern United States. It also includes certain related pipelines and infrastructure, including decommissioned and deactivated pipelines. Enbridge has operated, and frequently expanded, the Canadian Mainline since 1949. Effective September 1, 2015, the closing date of the Canadian Restructuring Plan, Enbridge transferred the Canadian Mainline to the Fund Group – see Canadian Restructuring Plan. The Lakehead System is the portion of the mainline system in the United States that continues to be managed by Enbridge through its subsidiaries, EEP and EELP – see Liquids Pipelines – Lakehead System. Competitive Toll Settlement The CTS is the current framework governing tolls paid for products shipped on the Canadian Mainline, with the exception of Lines 8 and 9 which are tolled on a separate basis. The 10-year settlement was negotiated by representatives of Enbridge, the Canadian Association of Petroleum Producers and shippers on the Canadian Mainline. It was approved by the NEB on June 24, 2011 and took effect on July 1, 2011. The CTS provides for a Canadian Local Toll (CLT) for deliveries within western Canada, which is based on the 2011 Incentive Tolling Settlement toll, as well as an IJT for crude oil shipments originating in western Canada on the Canadian Mainline and delivered into the United States, via the Lakehead System, and into eastern Canada. These tolls are denominated in United States dollars. The IJT is designed to provide shippers on the mainline system with a stable and competitive long-term toll, thereby preserving and enhancing throughput on both the Canadian Mainline and the Lakehead System. The IJT and the CLT were both established at the time of implementation of the CTS and are adjusted annually, on July 1 of each year, at a rate equal to 75% of the Canada Gross Domestic Product at Market Price Index published by Statistics Canada. Certain events may trigger a renegotiation of the CTS by Enbridge or the shippers. These include (i) a regulatory change that results in cumulative capital expenditures for integrity work on the Canadian Mainline increasing by more than $100 million, or (ii) if the nine month average volume on the Canadian Mainline, ex-Gretna, Manitoba, falls below the minimum threshold volume (currently 1.35 million bpd). If a renegotiation of the CTS is triggered, Enbridge and the shippers will meet and use reasonable efforts to agree on how the CTS can be amended to accommodate the event. If Enbridge and the shippers are unable to agree on the manner in which the CTS is to be amended, then, absent an extension to the renegotiation period, the CTS will terminate and Enbridge will need to ﬁle a new toll application for the Canadian Mainline. Two years prior to the end of the term of the CTS, Enbridge and the shippers will establish a group for the purposes of negotiating a new settlement to replace the CTS once it expires. Although the CTS has a 10-year term, it does not require shippers to Changes in the Canadian Mainline IJT Residual Benchmark Toll are commit to certain volumes. Shippers nominate volumes on a monthly inversely related to the Lakehead System Toll, which was higher in basis and Enbridge allocates capacity to maximize the efficiency 2016 due to the recovery of incremental costs associated with EEP’s of the Canadian Mainline. growth projects. Local tolls for service on the Lakehead System are not affected by In addition, Canadian Mainline adjusted EBIT reﬂected the impact the CTS and continue to be established pursuant to the Lakehead of a lower period-over-period exchange rate used to record System’s existing toll agreements, as described under Lakehead the Canadian Mainline revenues. The IJT Benchmark Toll and System below. Under the terms of the IJT agreement between Enbridge and EEP, the Canadian Mainline’s share of the IJT toll relating to pipeline transportation of a batch from any western Canada receipt point to the United States border is equal to the IJT toll applicable to that batch’s United States delivery point less the Lakehead System’s local toll to that delivery point. This amount is referred to as the Canadian Mainline IJT Residual Benchmark Toll and is denominated in United States dollars. Results of Operations its components are set in United States dollars and the majority of the Company’s foreign exchange risk on Canadian Mainline revenue is hedged. For the year ended December 31, 2016, the effective hedged rate for the translation of Canadian Mainline United States dollar transactional revenues was $1.07 compared with $1.10 for the corresponding 2015 period. In addition to the factors noted above, which partially offset the increase in Canadian Mainline adjusted EBIT for the year ended December 31, 2016, higher power costs associated with higher throughput and higher operating and administrative expense to Canadian Mainline adjusted EBIT was $931 million for the year ended support increased business activities also partially offset the increase. December 31, 2016 compared with $896 million for the year ended December 31, 2015. The year-over-year increase reﬂected higher throughput driven by strong oil sands production combined with contributions from new assets placed into service in 2015, the most prominent being the expansion of the Company’s mainline system The decrease in Canadian Mainline IJT Residual Benchmark Toll and lower foreign exchange hedge rate also resulted in a decrease in Canadian Mainline adjusted EBIT for the fourth quarter of 2016 compared with the fourth quarter of 2015. completed in the third quarter of 2015 and the reversal and expansion In 2015, the Company commenced collecting, in its tolls, NEB of Line 9B completed in the fourth quarter of 2015, as well as new surcharges for certain system expansions, including the Edmonton to Hardisty Expansion that was completed in the second quarter of 2015. Higher throughput on the Canadian Mainline also reﬂected mandated future abandonment costs from shippers. Approximately $45 million in revenues were recorded for the year ended December 31, 2016 (2015 – $38 million), but these amounts were offset by a corresponding increase in operating and administrative increased downstream demand throughout 2016 from the completion expense in the respective periods. For further details, refer to Critical of the Southern Access Extension in the fourth quarter of 2015. Accounting Estimates. Adjusted EBIT from Southern Access Extension is reported within Feeder Pipelines and Other. Higher terminalling revenues also contributed to an increase in adjusted EBIT for the year ended December 31, 2016. The positive effect of increased capacity on Canadian Mainline throughput discussed above was partially offset in the second quarter of 2016 by the impact of extreme wildﬁres in northeastern Alberta. The wildﬁres resulted in a curtailment of production from oil sands facilities and certain of the Company’s upstream pipelines and terminal facilities were temporarily shut down resulting in a disruption of service on Enbridge’s Regional Oil Sands System with corresponding impacts on deliveries to Enbridge’s downstream pipelines, including the Canadian Mainline. In the third quarter of 2016, throughput on the Company’s mainline system and overall system utilization strengthened. The impact of the wildﬁres for the year ended December 31, 2016 on Canadian Mainline adjusted EBIT has remained unchanged since the end of the second quarter of 2016 at approximately $30 million. For further details on the wildﬁres, refer to Liquids Pipelines – Impact of Wildﬁres in Northeastern Alberta. Canadian Mainline adjusted EBIT was $896 million for the year ended December 31, 2015 compared with $663 million for the year ended December 31, 2014. The year-over-year increase reﬂected higher throughput from strong oil sands production combined with strong reﬁnery demand in the midwest market partly due to a start-up of a midwest reﬁnery’s conversion to heavy oil processing in the second quarter of 2014. Higher throughput in the second half of 2015 was also achieved from the expansion of the Company’s mainline system completed in July 2015 and through continued efforts by the Company to optimize capacity utilization and to enhance scheduling efficiency with shippers. Although throughput increased relative to the comparative periods in 2014, further throughput growth in 2015 was hindered by upstream plant maintenance in Alberta during the second and third quarters which impacted light volumes, and an unplanned shutdown of a midwest reﬁnery that impacted the takeaway of heavy volumes in the third quarter. These negative impacts on throughput were alleviated towards the latter part of the fourth quarter of 2015. Other factors contributing to an increase in adjusted EBIT were higher terminalling revenues and the impact of a higher rate on hedges used to convert Year-over-year growth in Canadian Mainline adjusted EBIT was United States dollar denominated revenue. For the year ended also affected by a lower average Canadian Mainline IJT Residual December 31, 2015, the effective hedged rate for the translation Benchmark Toll. Effective April 1, 2016, Canadian Mainline IJT of Canadian Mainline United States dollar transactional revenues Residual Benchmark Toll decreased from US$1.63 to US$1.46, was $1.10, compared with $1.02 for the corresponding 2014 period. which more than offset the effects of the higher toll charged during In addition, Canadian Mainline fourth quarter of 2015 adjusted EBIT the ﬁrst quarter of 2016. Effective July 1, 2016, Canadian Mainline also reﬂected one month of revenues from Line 9B which was placed IJT Residual Benchmark Toll increased slightly to US$1.47. into service in December 2015. Management’s Discussion & Analysis 53 Partially offsetting the positive factors noted above was a lower year-over-year average Canadian Mainline IJT Residual Benchmark Toll, although this impact lessened commencing the second quarter of 2015 as effective April 1, 2015, this toll increased by US$0.10 per barrel to US$1.63 per barrel. Also mitigating the impact of a lower Canadian Mainline IJT Residual Benchmark Toll were new surcharges for certain system expansions as noted above. Other factors which negatively impacted adjusted EBIT were higher power costs associated with higher throughput and higher depreciation expense due to an increased asset base Supplemental information on Canadian Mainline adjusted earnings for the years ended December 31, 2016, 2015 and 2014 is provided below. December 31, (United States dollars per barrel) IJT Benchmark Toll1 Lakehead System Local Toll2 Canadian Mainline IJT Residual Benchmark Toll3 2016 2015 2014 $4.05 $2.58 $1.47 $4.07 $2.44 $1.63 $4.02 $2.49 $1.53 1 The IJT Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil. Effective July 1, 2014, the IJT Benchmark Toll increased from US$3.98 to US$4.02 and increased to US$4.07 effective July 1, 2015. Effective July 1, 2016, this toll decreased to US$4.05. 2 The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. In 2014, EEP delayed its annual April 1 tariff ﬁling for its Lakehead System as it was in negotiations with the Canadian Association of Petroleum Producers concerning certain components of the tariff rate structure. The toll application was ﬁled with the Federal Energy Regulatory Commission (FERC) on June 27, 2014, and effective August 1, 2014, the Lakehead System Local Toll increased from US$2.17 to US$2.49. Effective April 1, 2015, the Lakehead System Local Toll decreased from US$2.49 to US$2.39 and effective July 1, 2015, this toll increased to US$2.44. Effective April 1, 2016, this toll increased to US$2.61 and effective July 1, 2016, this toll decreased to US$2.58. 3 The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll and the Lakehead System Local Toll. Effective July 1, 2014, this toll increased from US$1.81 to US$1.85 and subsequently decreased to US$1.53 effective August 1, 2014, coinciding with the revised Lakehead System Local Toll. Effective April 1, 2015, the Canadian Mainline IJT Residual Benchmark Toll increased to US$1.63. Effective April 1, 2016, this toll decreased to US$1.46, coinciding with the revised Lakehead System Local Toll. Effective July 1, 2016, this toll increased to US$1.47. Throughput Volume1 (thousands of bpd) 2016 2015 2014 Q1 Q2 Q3 Q4 Full Year 2,543 2,210 1,904 2,242 2,073 1,968 2,353 2,212 2,039 2,481 2,243 2,066 2,405 2,185 1,995 1 Average throughput volume represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada. Canadian Mainline revenues include the portion of the system covered by the CTS as well as revenues from Lines 8 and 9 in eastern Canada. Lines 8 and 9 are currently tolled on a separate basis and comprise a relatively small proportion of total Canadian Mainline revenues. Line 9B was idled during 2014 for reversal and expansion. The project was completed and the 300,000 bpd line was placed into service in December 2015. CTS revenues include transportation revenues, the largest component, as well as allowance oil and revenues from receipt and delivery charges. Transportation revenues include revenues for volumes delivered off of the Canadian Mainline at Gretna, Manitoba and on to the Lakehead System, to which Canadian Mainline IJT residual tolls apply, and revenues for volumes delivered to other western Canada delivery points, to which the CLT applies. Despite the many factors that affect Canadian Mainline revenues, the primary determinants of those revenues will be throughput volume ex-Gretna, the United States dollar Canadian Mainline IJT Residual Benchmark Toll and the effective foreign exchange rate at which resultant revenues are converted into Canadian dollars. The Company currently utilizes derivative ﬁnancial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues. The exact relationship between the primary determinants and actual Canadian Mainline revenues will vary somewhat from quarter to quarter but is expected to be relatively stable on average for a year, absent a systematic shift in receipt and delivery point mix or in crude oil type mix. The largest components of operating and administrative expense are employee related costs, pipeline integrity, repairs and maintenance, rents and leases and property taxes. Operating and administrative costs are relatively insensitive to throughput volumes. 54 Enbridge Inc. 2016 Annual Report Canadian Mainline – Average Deliveries (thousands of barrels per day) 5 0 4 2 , 5 8 ,1 2 5 9 9 , 1 7 3 7 , 1 6 4 6 , 1 12 13 14 15 16 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. Lakehead System The Lakehead System consists of the United States portion of the mainline system that is managed by Enbridge through its subsidiaries, EEP and EELP. For an overview of the mainline system, refer to Liquids Pipelines – Canadian Mainline. Tariffs and Transportation Rates Transportation rates are governed by the FERC for deliveries from the Canada-United States border near Neche, North Dakota and from Clearbrook, Minnesota to certain principal delivery points. The Lakehead System periodically adjusts these transportation rates as allowed under the FERC’s index methodology and tariff agreements, the main components of which are base rates and Facilities Surcharge Mechanism. Base rates, the base portion of the transportation rates for the Lakehead System, are subject to an annual adjustment which cannot exceed established ceiling rates as approved by the FERC. The Facilities Surcharge Mechanism allows the Lakehead System to recover costs associated with certain shipper- requested projects through an incremental surcharge in addition to the existing base rates, and is subject to annual adjustment. Throughput Volume1 (thousands of bpd) 2016 2015 2014 Q1 Q2 Q3 Q4 Full Year 2,735 2,330 2,000 2,440 2,208 2,088 2,495 2,338 2,172 2,624 2,388 2,187 2,574 2,315 2,113 1 Average throughput volume represents mainline system deliveries to the United States midwest and eastern Canada. Results of Operations Lakehead System adjusted EBIT was $1,425 million for the year ended December 31, 2016 compared with $1,108 million for the year ended December 31, 2015. The year-over-year increase in adjusted EBIT reﬂected stronger operating performance, as well as the favourable effect of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2016 compared with 2015. Excluding the impact of foreign exchange translation to Canadian dollars, Lakehead System adjusted EBIT was US$1,074 million for the year ended December 31, 2016 compared with US$868 million for the year ended December 31, 2015. The year-over-year increase reﬂected higher Lakehead System Local Toll and higher throughput, as well as contributions from new assets placed into service in 2015, the most prominent being the expansion of the Company’s mainline system completed in the third quarter of 2015. As discussed under Canadian Mainline above, higher throughput on the Lakehead System in 2016 also reﬂected increased downstream demand resulting from the completion of Southern Access Extension and the reversal and expansion of Line 9B. However, deliveries to the Lakehead System from the Canadian Mainline were lower during the second quarter of 2016, as a result of the northeastern Alberta wildﬁres. The negative impact of the wildﬁres for the year ended December 31, 2016 on Lakehead System adjusted EBIT has remained unchanged since the end of the second quarter of 2016 at approximately $38 million. Also partially offsetting the year-over-year increase in adjusted EBIT were higher operating and administrative costs and higher depreciation expense from an increased asset base. Adjusted EBIT for the year ended December 31, 2016 also reﬂected higher power costs associated with higher throughput. As noted above, positively impacting Lakehead System adjusted EBIT for the year ended December 31, 2016 was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in 2016. The Average Exchange Rate was $1.32 for the year ended December 31, 2016 compared with $1.28 in the corresponding 2015 period. A portion of Lakehead System United States dollar EBIT is Management’s Discussion & Analysis 55 hedged as part of the Company’s enterprise-wide ﬁnancial risk of US$38.31 per unit, which was determined based on the trailing management program. The Company uses foreign exchange ﬁve-day volume-weighted average price of EEP’s Class A common units. derivative instruments to manage the foreign exchange risk arising from its United States businesses, including the Lakehead System, and realized gains and losses from these derivative instruments are reported within Eliminations and Other. For further details refer to Eliminations and Other. The aggregate consideration of US$1 billion corresponded to an approximate 10.7 times multiple of then expected 2015 Alberta Clipper earnings before interest, tax, depreciation and amortization (EBITDA). The cumulative adjusted EBITDA of the Alberta Clipper Pipeline for ﬁscal years 2015 and 2016 exceeded the minimum Lakehead System adjusted EBIT was $1,108 million for the year required threshold set under the agreement. ended December 31, 2015 compared with $836 million for the year ended December 31, 2014 .The year-over-year increase in adjusted EBIT reﬂected stronger operating performance, as well as the favourable effect of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2015 compared with 2014. The United States segment of the Alberta Clipper Pipeline is a 523-kilometre (325-mile), 36-inch diameter crude oil pipeline from the United States border near Neche, North Dakota to Superior, Wisconsin. The line had an initial capacity of 450,000 bpd and was constructed under the terms of a joint funding agreement under which Enbridge funded two-thirds of the capital costs in return for Excluding the impact of foreign exchange translation to Canadian a corresponding economic interest in the earnings and cash ﬂow dollars, Lakehead System adjusted EBIT was US$868 million for the year ended December 31, 2015 compared with US$756 million for the year ended December 31, 2014. The year-over-year increase reﬂected higher throughput and tolls, as well as contributions from new assets placed into service in 2015 and 2014, the most prominent being the expansion of the Company’s mainline system completed in July 2015 and the replacement and expansion of Line 6B completed in 2014. Partially offsetting the increase in adjusted EBIT were higher operating and administrative costs, incremental power costs associated with higher throughput and higher depreciation expense from an increased asset base. As noted above, positively impacting year-over-year adjusted EBIT was the favourable impact of translating United States dollar earnings at a higher Average Exchange Rate in 2015. The Average Exchange Rate was $1.28 for the year ended December 31, 2015 compared with $1.10 for the comparative period of 2014. As noted above, a portion of Lakehead System United States dollar EBIT was hedged as part of the Company’s enterprise-wide ﬁnancial risk management program. For further details refer to Eliminations and Other. Lakehead System—Alberta Clipper Drop Down On January 2, 2015, Enbridge completed the transfer of its 66.7% interest in the United States segment of the Alberta Clipper Pipeline, held through a wholly-owned Enbridge subsidiary in the United States, to EEP. At the time of the transfer, EEP already owned the remaining 33.3% interest in the United States segment of Alberta from the investment. In 2015, the line was expanded in two phases to a capacity of 800,000 bpd through the addition of increased pumping horsepower; however, EEP is awaiting an amendment to the current Presidential border crossing permit to allow for operation of Alberta Clipper Pipeline at its currently planned operating capacity of 800,000 bpd. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with any delays in obtaining this amendment. The required expansion investments are subject to separate joint funding arrangements between Enbridge and EEP and were not included as part of the above noted drop down transaction. Refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Lakehead System Mainline Expansion (EEP). Lakehead System Lines 6A and 6B Crude Oil Releases Line 6B Crude Oil Release On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Kalamazoo River via Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 61 kilometres (38 miles) of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. EEP continues to evaluate the need for additional remediation Clipper. Aggregate consideration for the transfer was US$1 billion, activities and is performing the necessary restoration and monitoring consisting of approximately US$694 million of Class E equity units of the areas affected by the Line 6B crude oil release. All the initiatives issued to Enbridge by EEP and the repayment of approximately EEP is undertaking in the monitoring and restoration phase are US$306 million of indebtedness owed to Enbridge. The terms intended to restore the crude oil release area to the satisfaction of the transfer were reviewed and recommended by an independent of the appropriate regulatory authorities. committee of EEP. In May 2015, EEP reached a settlement with the Michigan Department The Class E units issued to Enbridge are entitled to the same of Environmental Quality and the Michigan Attorney General’s offices distributions as the Class A common units held by the public and regarding the Line 6B crude oil release. As stipulated in the settlement, are convertible into Class A common units on a one-for-one basis EEP agrees to: (1) provide at least 300 acres of wetland through at Enbridge’s option. However, the Class E units were not entitled restoration, creation, or banked wetland credits, to remain as wetland to distributions with respect to the quarter ended December 31, 2014. in perpetuity; (2) pay US$5 million as mitigation for impacts to the The Class E units are redeemable at EEP’s option after 30 years, if not banks, bottomlands, and ﬂow of Talmadge Creek and the Kalamazoo converted earlier by Enbridge. The Class E units have a liquidation River for the purpose of enhancing the Kalamazoo River watershed preference equal to their notional value at December 23, 2014 and restoring stream ﬂows in the River; (3) continue to reimburse 56 Enbridge Inc. 2016 Annual Report the State of Michigan for costs arising from oversight of EEP customary for its industry and includes coverage for environmental activities since the release; and (4) continue monitoring, incidents excluding costs for ﬁnes and penalties. 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. Enbridge has renewed its comprehensive property and liability insurance programs with a liability program aggregate limit of US$900 million, which includes sudden and accidental pollution liability. The insurance programs are effective May 1, 2016 through As at December 31, 2016, EEP’s total cost estimate for the Line 6B April 30, 2017. In the unlikely event that multiple insurable incidents crude oil release remains at US$1.2 billion ($195 million after-tax which in aggregate exceed coverage limits occur within the same attributable to Enbridge) since December 31, 2015. This includes insurance period, the total insurance coverage will be allocated a reduction of estimated remediation efforts offset by an increase among Enbridge entities on an equitable basis based on an insurance in civil penalties under the Clean Water Act of the United States, allocation agreement among Enbridge and its subsidiaries. as described below under Legal and Regulatory Proceedings. In addition, in the fourth quarter of 2016, the cost accruals were reduced by US$8 million ($1 million after-tax attributable to Enbridge), mainly due to optimization of EEP’s remedial investigation reporting and savings related to EEP’s residual oil monitoring and maintenance. A majority of the costs incurred in connection with the crude oil release for Line 6B, other than ﬁnes and penalties, are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability for Enbridge and its affiliates. Including EEP’s remediation spending through December 31, 2016, costs related to Line 6B exceeded Expected losses associated with the Line 6B crude oil release the limits of the coverage available under this insurance policy. included those costs that were considered probable and that could Additionally, ﬁnes and penalties would not be covered under prior be reasonably estimated at December 31, 2016. Despite the efforts or existing insurance policy. As at December 31, 2016, EEP has EEP has made to ensure the reasonableness of its estimates, recorded total insurance recoveries of US$547 million ($80 million there continues to be the potential for EEP to incur additional after-tax attributable to Enbridge) for the Line 6B crude oil release costs in connection with this crude oil release due to variations out of the US$650 million aggregate limit. EEP will record receivables in any or all of the cost categories, including modiﬁed or revised for additional amounts it claims for recovery pursuant to its insurance requirements from regulatory agencies. policies during the period it deems recovery to be probable. 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 In March 2013, EEP and Enbridge ﬁled a lawsuit against the insurers of US$145 million of coverage, as one particular insurer is disputing the recovery eligibility for costs related to EEP’s claim on the Line 6B crude oil release and the other remaining insurers asserted that their payment is predicated on the outcome of the recovery from that insurer. EEP received a partial recovery payment of US$42 million from the other remaining insurers and amended its lawsuit such that it includes only one insurer. a small amount of the crude oil was recovered. EEP completed Of the remaining US$103 million coverage limit, US$85 million excavation and replacement of the pipeline segment and returned was the subject matter of a lawsuit against one particular insurer. it to service on September 17, 2010. In March 2015, Enbridge reached an agreement with that insurer EEP has completed the cleanup, remediation and restoration of the areas affected by the release. In October 2013, the National Transportation Safety Board publicly posted their ﬁnal report related to the Line 6A crude oil release which states the probable cause to submit the US$85 million claim to binding arbitration. The recovery of the remaining US$18 million is awaiting resolution of that arbitration. While EEP believes that those costs are eligible for recovery, there can be no assurance that EEP will prevail. of the crude oil release was erosion caused by a leaking water pipe In addition, and separate from the ongoing Line 6B claim, during resulting from an improperly installed third-party water service line the year ended December 31, 2016, EEP recorded an insurance below EEP’s oil pipeline. The total estimated cost for the Line 6A crude oil release was approximately US$53 million ($7 million after-tax attributable recovery of US$10 million ($1 million after-tax attributable to Enbridge) associated with the Line 6A Romeoville crude oil release. This is the total insurance recovery available for the Line 6A incident. to Enbridge) before insurance recoveries and including ﬁnes and Legal and Regulatory Proceedings penalties. These costs included emergency response, environmental remediation and cleanup activities with the crude oil release. As at December 31, 2016, EEP has no remaining estimated liability. Insurance EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. On May 1 of each year, the commercial liability insurance program is renewed and includes coverage that is consistent with coverage considered A number of United States governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Two actions or claims are pending against Enbridge, EEP or their affiliates in United States state courts in connection with the Line 6B crude oil release. Based on the current status of these cases, the Company does not expect the outcome of these actions to be material to its results of operations or ﬁnancial condition. Management’s Discussion & Analysis 57 Line 6A and 6B Fines and Penalties As at December 31, 2016, included in EEP’s total estimated costs related to the Line 6B crude oil release were US$69 million in ﬁnes and penalties. Of this amount, US$61 million relates to civil penalties under the Clean Water Act of the United States, which EEP fully accrued but has not paid, pending approval of the Consent Decree, as described below. In June 2015, Enbridge reached a separate agreement with the United States (Federal Natural Resources Damages Trustees), State of Michigan (State Natural Resources Damages Trustees), Match-E-Be-Nash- She-Wish Band of the Potawatomi Indians, and the Nottawaseppi Huron Band of the Potawatomi Indians, and paid approximately US$4 million that was accrued to cover a variety of projects, including the restoration of 175 acres of oak savanna in the Fort Custer State Recreation Area and wild rice beds along the Kalamazoo River. One claim related to the Line 6A crude oil release had been ﬁled against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court in connection with this crude oil release. On February 20, 2015, EEP agreed to a consent order releasing it from any claims, liability, or penalties. Consent Decree On July 20, 2016, a Consent Decree was ﬁled with the Western District of Michigan Southern Division (the Court). The Consent Decree is EEP’s signed settlement agreement with the Environmental Protection Agency (EPA) and the United States Department of Justice regarding Lines 6A and 6B crude oil releases. Pursuant to the Consent Decree, EEP will pay US$62 million in civil penalties: US$61 million in respect of Line 6B and US$1 million in respect of Line 6A. The Consent Decree will take effect upon approval by the Court. In addition to the monetary ﬁnes and penalties discussed above, the Consent Decree calls for replacement of Line 3, which EEP initiated in 2014 and is currently under regulatory review in the State of Minnesota as described in Growth Projects – Commercially Secured Projects – Liquids Pipelines – Line 3 Replacement Program – United States Line 3 Replacement Program (EEP). The Consent Decree contains a variety of injunctive measures, including, but not limited to, enhancements to EEP’s comprehensive in-line inspection-based spill prevention program; enhanced measures to protect the Straits of Mackinac; improved leak detection requirements; installation of new valves to control product loss in the event of an incident; continued enhancement of control room operations; and improved spill response capabilities. Collectively, these measures build on continuous improvements implemented since 2010 to EEP’s leak detection program, control centre operations and emergency response program. EEP estimates the total cost of these measures to be approximately US$110 million, most of which is already incorporated into existing long-term capital investment and operational expense planning and guidance. Compliance with the terms of the Consent Decree is not expected to materially impact the overall ﬁnancial performance of EEP or the Company. Regional Oil Sands System Regional Oil Sands System The Regional Oil Sands System includes three intra-Alberta long haul pipelines, the Athabasca Pipeline, Waupisoo Pipeline and Woodland Pipeline and two large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta and the Cheecham Terminal, located south of Fort McMurray. The Regional Oil Sands System also includes the Wood Buffalo Pipeline and Norealis Pipeline, each of which provides access for oil sands production from north Woodland Pipeline Athabasca Terminal Wood Buffalo Pipeline AOC Hangingstone Lateral of Fort McMurray to the Cheecham Terminal. There are also other Woodland Pipeline Extention facilities such as the MacKay River, Christina Lake, Surmont, Long Lake and AOC laterals and related facilities. Regional Oil Sands System currently serves nine producing oil sands projects. Effective September 1, 2015, the closing date of the Canadian Restructuring Plan, Enbridge transferred the Regional Oil Sands System to the Fund Group – see Canadian Restructuring Plan. Waupisoo Pipeline Edmonton ALBERTA The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic and heavy oil pipeline. Built in 1999, it links the Athabasca oil Assets in Operation sands in the Fort McMurray region to the major Alberta pipeline 58 Enbridge Inc. 2016 Annual Report Norealis Norealis Terminal Terminal Norealis Pipeline Norealis Pipeline Cheecham Cheecham Terminal Terminal Kirby Lake Kirby Lake Terminal Terminal Athabasca Pipeline Athabasca Pipeline Sunday Creek Terminal Hardisty Enbridge Mainline hub at Hardisty, Alberta. The Athabasca Pipeline’s capacity is 570,000 bpd, depending on crude slate. The Company has long-term take-or-pay and non take-or-pay agreements with multiple shippers on the Athabasca Pipeline. Revenues are recorded based on the contract terms negotiated with the major shippers, rather than the cash tolls collected. In January 2017, the Company also completed the twinning of the southern section of the Athabasca Pipeline with a 36-inch diameter pipeline from Kirby Lake, Alberta to its Hardisty crude oil hub, as discussed under Growth Projects – Commercially Secured Projects – Liquids Pipelines – Regional Oil Sands Optimization Project (the Fund Group). The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered service in 2008 and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline originates at the Cheecham Terminal and terminates at the major Alberta pipeline hub at Edmonton. The pipeline has a capacity of 550,000 bpd, depending on crude slate. The Company has long-term take-or-pay commitments with multiple shippers on the Waupisoo Pipeline who have collectively contracted for 80% to 90% of the capacity, subject to the timing of when shippers’ commitments commence and expire. The Woodland Pipeline consists of Line 49 and Line 70 (Woodland Pipeline Extension) which were constructed in phases. In 2012, EPAI entered into a transportation agreement with Imperial Oil Resources Ventures Limited (IORVL) and ExxonMobil Canada Properties (ExxonMobil) to provide for the transportation of blended bitumen from the Kearl oil sands mine to the major Alberta pipeline hub at Edmonton. The construction of the Woodland Pipeline was phased with the Kearl oil sands mine expansion, with the ﬁrst phase involving construction of a 140-kilometre (87-mile) 36-inch diameter pipeline from the mine to the Cheecham Terminal, and service on the Company’s existing Waupisoo Pipeline from Cheecham to the Edmonton area. The completed Woodland Pipeline (Line 49) was placed into service in 2013, commensurate with the start-up of the Kearl oil sands mine. The second phase involved the Woodland Pipeline Extension project, which under a joint venture among EPAI, IORVL and ExxonMobil, extended the Woodland Pipeline south from the Company’s Cheecham Terminal to its Edmonton Terminal. The extension involved the construction of a 385-kilometre (239-mile) 36-inch diameter pipeline which was completed and entered service in 2015, adding 379,000 bpd of capacity to the Regional Oil Sands System. The Company has long-term commitments on the Woodland Pipeline. Results of Operations Regional Oil Sands System adjusted EBIT for the year ended December 31, 2016 was $384 million compared with $341 million for the year ended December 31, 2015. The year- over-year increase in adjusted EBIT primarily reﬂected contributions from assets placed into service in the second half of 2015, including the Sunday Creek Terminal and Woodland Pipeline Extension projects that were placed into service in the third quarter of 2015 and the AOC Hangingstone Lateral which was completed in December 2015. Regional Oil Sands System adjusted EBIT also beneﬁtted from higher contracted volumes on Waupisoo Pipeline in the fourth quarter of 2016 compared with the fourth quarter of 2015. However, the year-over-year increase in adjusted EBIT was partially offset by the effects of the wildﬁres in northeastern Alberta during the second quarter of 2016, as discussed under Liquids Pipelines – Impact of Wildﬁres in Northeastern Alberta, which negatively impacted Regional Oil Sands System adjusted EBIT by approximately $6 million. Regional Oil Sands System adjusted EBIT for the year ended December 31, 2015 was $341 million compared with $301 million for the year ended December 31, 2014. Higher adjusted EBIT primarily reﬂected contributions from assets placed into service in 2014 and 2015, including the Sunday Creek Terminal and Woodland Pipeline Extension projects that were placed into service in the third quarter of 2015, Surmont Phase 2 Expansion project that was placed into service in phases in November 2014 and March 2015, as well as Norealis Pipeline which was completed in April 2014. These positive impacts were partially offset by higher depreciation expense from a larger asset base, as well as a reduction in contracted volumes on the Athabasca Mainline, mitigated in part by higher uncommitted volumes on this pipeline. Line 37 Crude Oil Release Regional Oil Sands System – Average Deliveries (thousands of barrels per day) 2 3 0 , 1 4 0 0 , 1 3 0 7 3 3 5 4 1 4 12 13 14 151 161 1 Following the completion of the Woodland Pipeline Extension in July 2015, volumes are for the Athabasca mainline, Waupisoo Pipeline and Woodland Pipeline and exclude laterals on the Regional Oil Sands System. On June 22, 2013, Enbridge reported a release of an estimated 1,300 barrels of light synthetic crude oil on its Line 37 pipeline approximately two kilometres north of Enbridge’s Cheecham Terminal. Management’s Discussion & Analysis 59 The release was caused by unusually high water levels in the region Pipeline’s right-of-way. Flanagan South has an initial design that triggered ground movement on the right-of-way. The oil released capacity of approximately 600,000 bpd; however, in its initial from Line 37 was recovered and on July 11, 2013, Line 37 returned years, it is not expected to operate at its full design capacity. to service at reduced operating pressure. Normal operating pressure was restored on July 29, 2013 after ﬁnalization of geotechnical Spearhead Pipeline analysis. Investigations into the incident were conducted by the Spearhead Pipeline is a long-haul pipeline that delivers crude oil Alberta Energy Regulator and Environment Canada. Each of these from Flanagan, Illinois, a delivery point on the Lakehead System investigations was completed and closed by the applicable regulator to Cushing, Oklahoma. The pipeline was originally placed into without any penalties or ﬁnes being imposed on Enbridge. service in 2006 and an expansion was completed in mid-2009, For the years ended December 31, 2015 and 2014, the Company’s EBIT reﬂected remediation and long-term stabilization costs of approximately $6 million and $5 million before insurance recoveries, respectively. Lost revenues associated with the shutdown of Line 37 and the pipelines sharing a corridor with Line 37 were minimal. At the time of the Line 37 crude oil release, Enbridge carried liability insurance for sudden and accidental pollution events, subject to a $10 million deductible. The integrity and stability costs associated with remediating the impact of the high water levels were precautionary in nature and not covered by insurance. Enbridge expects to record receivables for amounts claimed for recovery pursuant to its insurance policies during the period that it deems realization of the claim for recovery to be probable. For the years ended December 31, 2016, 2015 and 2014, Enbridge recognized insurance recoveries of $5 million, $32 million and $10 million, respectively. Mid-Continent and Gulf Coast Mid-Continent and Gulf Coast includes Seaway and Flanagan South Pipelines, Spearhead Pipeline, as well as the Mid-Continent System that is managed by Enbridge through its subsidiary, EEP. increasing capacity from 125,000 bpd to 193,300 bpd. Initial committed shippers and expansion shippers currently account for more than 70% of the 193,300 bpd capacity on Spearhead Pipeline. Both the initial committed shippers and expansion shippers were required to enter into 10-year shipping commitments at negotiated rates that were offered during the open season process. In March 2015, the commitment agreements with the initial committed shippers were extended for an additional 10 years. The balance of the capacity is currently available to uncommitted shippers on a spot basis at FERC approved rates. Mid-Continent System The Mid-Continent System is comprised of the Ozark Pipeline and storage terminals at Cushing, Oklahoma and Flanagan, Illinois. The Ozark Pipeline transports crude oil from Cushing, Oklahoma to Wood River, Illinois, where it delivers to a third-party reﬁnery and interconnects with other third-party pipelines. In December 2016, the Company entered into an agreement to sell the Ozark Pipeline to a subsidiary of MPLX LP for cash proceeds of approximately $294 million (US$219 million), including $13 million (US$10 million) in reimbursable costs for additional capital spent by the Company up to the closing date of the transaction. Subject to certain pre-closing conditions, the transaction is expected to close by the end of the ﬁrst Seaway Pipeline quarter of 2017. In 2011, Enbridge acquired a 50% interest in the 1,078-kilometre (670-mile) Seaway Crude Pipeline System (Seaway Pipeline), including the 805-kilometre (500-mile), 30-inch diameter long-haul system between Cushing, Oklahoma and Freeport, Texas, as well as the Texas City Terminal and Distribution System which serves reﬁneries in the Houston and Texas City areas. Seaway Pipeline also includes The storage terminals consist of 100 individual storage tanks ranging in size from 78,000 to 575,000 barrels. Of the approximately 23.6 million barrels of storage shell capacity on the Mid-Continent System, the Cushing terminal accounts for approximately 20.1 million barrels. A portion of the storage facilities is used for operational purposes, while the remainder of the facilities are contracted with various crude 7.4 million barrels of crude oil tankage on the Texas Gulf Coast. oil market participants for their term storage requirements. The ﬂow direction of Seaway Pipeline was reversed in 2012, enabling Results of Operations it to transport crude from the oversupplied hub in Cushing, Oklahoma to the Gulf Coast. Further pump station additions and modiﬁcations were completed early 2013, increasing capacity available to shippers from an initial 150,000 bpd to up to approximately 400,000 bpd, depending on crude oil slate. In late 2014, a second line, the Seaway Pipeline Twin, was placed into service to more than double the existing capacity to 850,000 bpd. Seaway Pipeline also includes a 161-kilometre (100-mile) pipeline from the ECHO crude oil terminal Mid-Continent and Gulf Coast adjusted EBIT for the year ended December 31, 2016 was $656 million compared with adjusted EBIT of $516 million for the year ended December 31, 2015. The year- over-year increase in adjusted EBIT reﬂected stronger operating performance, as well as the favourable effect of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2016 compared with 2015. in Houston, Texas to the Port Arthur/Beaumont, Texas reﬁning centre. Excluding the impact of foreign exchange translation to Flanagan South Pipeline Canadian dollars, Mid-Continent and Gulf Coast adjusted EBIT was US$495 million for the year ended December 31, 2016 compared Flanagan South is a 950-kilometre (590-mile), 36-inch diameter with US$400 million for the year ended December 31, 2015. interstate crude oil pipeline that originates at the Company’s terminal The year-over-year increase in adjusted EBIT primarily reﬂected at Flanagan, Illinois and terminates in Cushing, Oklahoma. Flanagan higher transportation revenues resulting mainly from an increase South and associated pumping stations were completed in the fourth in the level of committed take-or-pay volumes on Flanagan South, quarter of 2014 and the majority of the pipeline parallels Spearhead as well as higher tariffs on Flanagan South in the ﬁrst half of 2016. 60 Enbridge Inc. 2016 Annual Report Throughput on Flanagan South is affected by Canadian Mainline Seaway Pipeline Regulatory Matters apportionment and the upstream apportionment experienced in the ﬁrst half of 2015 was partially alleviated in 2016 with the expansion of the Company’s mainline system completed in the third quarter of 2015. When committed shippers on Flanagan South are unable to satisfy their volume commitments due to apportionment, they are provided with temporary relief to make up those volumes during the course of their contracts or the apportioned volumes are added onto the end of the contract term. Partially offsetting the year-over-year increase in adjusted EBIT was lower throughput on Spearhead Pipeline due to a decline in demand for services in the second half of 2016. Seaway Pipeline ﬁled an application for market-based rates in December 2011. In February 2014, the FERC rejected Seaway Pipeline’s application but also set out a new methodology based on recent appellate court rulings for determining whether a pipeline has market power and invited Seaway Pipeline to reﬁle its market-based rate application consistent with the new policy. In December 2014, Seaway Pipeline ﬁled a new market-based rates application. Several parties ﬁled comments in opposition alleging that the application should be denied because Seaway Pipeline has market power in both its receipt and destination markets. On September 17, 2015, the FERC set the application for hearing Excluding the impact of foreign exchange translation to Canadian before an Administrative Law Judge (ALJ). On December 1, 2016, dollars, the decline in shippers’ demand on Spearhead Pipeline also the ALJ issued its decision which concluded that the Commission drove a decrease in Mid-Continent and Gulf Coast adjusted EBIT for should grant the application of Seaway Pipeline for authority the fourth quarter of 2016 compared with the fourth quarter of 2015. to charge market-based rates. The parties may ﬁle briefs during As noted above, positively impacting adjusted EBIT for the year ended December 31, 2016 was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in 2016. Similar to Lakehead System, a portion of Mid-Continent and Gulf Coast United States dollar EBIT is hedged as part of the Company’s enterprise-wide ﬁnancial risk management program and realized gains and losses from the derivative instruments used to hedge foreign exchange risk arising from the Company’s investment in United States businesses are reported within Eliminations and Other. For further details refer to Eliminations and Other. Mid-Continent and Gulf Coast adjusted EBIT for the year ended December 31, 2015 was $516 million compared with adjusted EBIT of $319 million for the year ended December 31, 2014. The year-over-year increase in adjusted EBIT reﬂected stronger operating performance, as well as the favourable effect of translating United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2015 compared with 2014. the ﬁrst quarter of 2017, and the Commissioners will review the entire record and issue a decision. There is no timeline for the FERC Commissioners to act and issue a decision. Additionally, in a February 1, 2016 order, the FERC upheld Seaway Pipeline’s current committed rate structure and reversed a prior ALJ decision reducing those rates to cost-based levels. With respect to the uncommitted rates, the FERC permitted Seaway Pipeline to include the full Enbridge purchase price (including goodwill) in rate base. FERC’s other cost-of-service rulings regarding the uncommitted rates were also largely favourable to Seaway Pipeline. A compliance ﬁling calculating revised rates was ﬁled on March 17, 2016. The FERC accepted the compliance ﬁling by order dated August 17, 2016. Seaway Pipeline has ﬁled new uncommitted rates in accordance with that order. Going forward, Seaway Pipeline’s uncommitted rates may be adjusted annually based on the FERC index, unless and until the FERC approves Seaway Pipeline’s application for market-based ratemaking authority. Southern Lights Pipeline Excluding the impact of foreign exchange translation to Canadian dollars, Mid-Continent and Gulf Coast adjusted EBIT was US$400 million for the year ended December 31, 2015 compared with US$287 million for the year ended December 31, 2014. The increase in adjusted EBIT primarily reﬂected the effects of Flanagan South and Seaway Pipeline Twin commencing operations in late 2014. During the ﬁrst half of 2015, as a result of Canadian Mainline apportionment, throughput on Seaway Pipeline and Flanagan South was lower than the throughput committed on these pipelines. However, this upstream apportionment was partially alleviated in the second half of 2015 through the expansion of the Company’s mainline system completed in July 2015. Southern Lights Pipeline is a fully-contracted single stream pipeline that ships diluent from the Manhattan Terminal near Chicago, Illinois to three western Canadian delivery facilities, located at the Edmonton and Hardisty terminals in Alberta and the Kerrobert terminal in Saskatchewan. This 180,000 bpd 16/18/20-inch diameter pipeline was placed into service mid-2010. Prior to the close of the Canadian Restructuring Plan, the Canadian portion of Southern Lights Pipeline (Southern Lights Canada) was owned by SL Canada, an Alberta limited partnership. Southern Lights US is owned by Enbridge Pipelines (Southern Lights) L.L.C., a Delaware limited liability company. Both Southern Lights Canada and Southern Lights US receive tariff revenues under long-term contracts with committed shippers. Also positively impacting year-over-year adjusted EBIT was Tariffs provide for recovery of all operating and debt ﬁnancing the favourable effect of translating United States dollar earnings costs plus a return on equity (ROE) of 10%. Southern Lights Pipeline at a higher Average Exchange Rate in 2015. As noted above, has assigned 10% of the capacity (18,000 bpd) for shippers a portion of Mid-Continent and Gulf Coast United States dollar to ship uncommitted volumes. EBIT was hedged as part of the Company’s enterprise-wide ﬁnancial risk management program. For further details refer to Eliminations and Other. As part of Enbridge’s sponsored vehicle strategy, on November 7, 2014, the Fund Group subscribed for and purchased Southern Lights Class A units which provide a deﬁned cash ﬂow stream to the Fund Group and represent the equity cash ﬂows derived from the core rate Management’s Discussion & Analysis 61 base of Southern Lights Pipeline until June 30, 2040 – see The Fund Results of Operations Group 2014 Drop Down Transaction. Enbridge has guaranteed payment of the quarterly distributions that the Fund Group receives, except in circumstances of force majeure, certain regulatory actions and shipper defaults that remain unrecovered under the shipper contracts. The Fund Group has options to negotiate extensions for two additional 10-year terms beyond 2040 and to participate in equity returns from future expansions of Southern Lights Pipeline. Bakken System adjusted EBIT for the year ended December 31, 2016 was $198 million compared with $213 million for the year ended December 31, 2015. The year-over-year decrease in adjusted EBIT reﬂected lower rates and lower rail revenues on the United States portion of the Bakken System. The decrease in adjusted EBIT was partially offset by the translation of United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2016 In addition, as part of the Canadian Restructuring Plan, effective compared with 2015. September 1, 2015, Enbridge transferred all Class B units of Southern Lights Canada to the Fund Group. Following the closing of the Transaction, the Fund Group holds all the ownership, economic interests and voting rights, direct and indirect, in Southern Lights Canada. Enbridge continues to indirectly own all of the Class B Units of Southern Lights US. Results of Operations Southern Lights Pipeline adjusted EBIT for the year ended December 31, 2016 was $168 million compared with $155 million for the year ended December 31, 2015. The increase in year-over-year adjusted EBIT reﬂected higher recovery of negotiated depreciation rates in 2016 transportation tolls. Southern Lights Pipeline adjusted EBIT for the year ended December 31, 2015 was $155 million compared with $121 million for the year ended December 31, 2014. The increase in year-over-year adjusted EBIT reﬂected higher recovery of negotiated depreciation rates in 2015 transportation tolls. Also positively impacting adjusted EBIT was the favourable impact of translating United States dollar earnings at a higher Average Exchange Rate in 2015 on the United States component of Southern Lights Pipelines. Bakken System The Bakken System is a joint operation that includes a Canadian entity and a United States entity. The United States portion Excluding the impact of foreign exchange translation to Canadian dollars, adjusted EBIT from Bakken System’s United States portion was US$131 million compared with US$155 million for the corresponding 2015 period. The decrease in year-over-year adjusted EBIT for the United States portion of the Bakken System was attributable to lower surcharge revenues as certain surcharge rates subject to an annual adjustment were decreased effective April 1, 2016, as well as lower rail revenues related to EEP’s Berthold rail facility due to expired contracts. These negative impacts were partially offset by the effects of higher throughput driven by enhanced downstream capacity on the mainline system and as a result of volumes shifting to pipelines from other higher cost transportation alternatives such as rail. As noted above, impacting adjusted EBIT for the year ended December 31, 2016 was the favourable effect of translating United States dollar earnings at a higher Average Exchange Rate in 2016. Similar to Lakehead System, a portion of the United States dollar EBIT of the Bakken System in the United States is hedged as part of the Company’s enterprise-wide ﬁnancial risk management program, and realized gains and losses from the derivative instruments used to hedge foreign exchange risk arising from the Company’s investment in United States businesses are reported within Eliminations and Other. For further details refer to Eliminations and Other. of the pipeline system extends from Berthold, North Dakota Bakken System adjusted EBIT for the year ended December 31, 2015 to the International Boundary near North Portal, North Dakota, was $213 million compared with $233 million for the year ended and connects to the Bakken Canada entity at the border to bring December 31, 2014. Within Bakken System adjusted EBIT for the year the crude oil into Cromer, Manitoba. The United States portion ended December 31, 2015 was US$155 million (2014 – US$198 million) of the Bakken System is comprised of a crude oil gathering and from its United States’ operations. interstate pipeline transportation system servicing the Williston Basin in North Dakota and Montana, which includes the Bakken and Three Forks formation. The gathering pipelines collect crude oil from nearly 80 different receipt facilities located throughout western North Dakota and eastern Montana, including nearly 20 third-party gathering pipeline connections, with delivery to a variety of interconnecting pipeline and rail export facilities. Tolls and Tariffs Tariffs on the United States portion of the Bakken System are governed by FERC and include a local tariff. The Canadian portion of the Bakken System is categorized as a Group 2 pipeline, and as such its tolls are regulated by the NEB on a complaint basis. Tolls are based on long-term take-or-pay agreements with anchor shippers. Excluding the impact of foreign exchange translation to Canadian dollars, the decrease in year-over-year adjusted EBIT was primarily attributed to the United States portion of the Bakken System which experienced lower surcharge revenues as certain surcharge rates subject to an annual adjustment were decreased effective April 1, 2015, as well as higher power costs related to higher throughput on the system. The increase in throughput year-over-year partially offset the year-over-year adjusted EBIT decrease and was attributed to the system’s enhanced market access and volumes shifting onto the system from other higher cost alternatives such as transportation by rail. In 2015, the United States portion of the Bakken System earnings were translated at a higher Average Exchange Rate. As noted above, a portion of the United States dollar EBIT from the Bakken System in the United States was hedged as part of the Company’s enterprise-wide ﬁnancial risk management program. For further details refer to Eliminations and Other. 62 Enbridge Inc. 2016 Annual Report Feeder Pipelines and Other Feeder Pipelines and Other primarily includes the Company’s 85% interest in Olympic Pipe Line Company (Olympic), the largest reﬁned products pipeline in the State of Washington, with a capacity to transport approximately 290,000 bpd of gasoline, diesel and jet fuel. It also includes the NW System, which transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta, interests in a number of liquids pipelines in the United States, including the recently completed Southern Access Extension, the Toledo Pipeline, which connects with the EEP mainline at Stockbridge, Michigan, and the Company’s 75% joint venture interest in Eddystone Rail, a unit-train unloading facility and related local pipeline infrastructure near Philadelphia, Pennsylvania that delivered Bakken and other light sweet crude oil to Philadelphia area reﬁneries, as well as business development costs related to Liquids Pipelines activities. Due to a signiﬁcant decrease in price spreads between Bakken crude oil and West Africa/Brent crude oil and increased competition in the region, demand for Eddystone Rail services dropped signiﬁcantly, resulting in an impairment of this facility in the second quarter of 2016. Feeder Pipelines and Other also includes the Hardisty Contract Terminal and Hardisty Storage Caverns located near Hardisty, Alberta, a key crude pipeline hub in western Canada. Also reported in Feeder Pipelines and Other results are contributions from the South Prairie Region assets which transport crude oil and NGL from producing ﬁelds and facilities in southeastern Saskatchewan and southwestern Manitoba to Cromer, Manitoba where products enter the mainline system to be transported to the United States or eastern Canada. On December 1, 2016, EIPLP completed the sale of the South Prairie Region assets to an unrelated party for cash proceeds of $1.08 billion. The sold assets consisted of certain liquids pipelines and related facilities in southeast Saskatchewan and southwest Manitoba, including the Saskatchewan Gathering and Weyburn gathering systems, as well as the Westspur trunk line. The shipper commercial arrangements and contracts associated with the South Prairie Region assets are expected to remain in place and the Company expects that the crude oil and NGL volumes delivered from the South Prairie Region assets will continue to ﬂow onto Enbridge’s Canadian Mainline at Cromer. Results of Operations Project completed in April 2014, incremental earnings from certain storage agreements, higher tolls and throughput on Toledo Pipeline, contributions from Southern Access Extension which was placed into service in December 2015 and higher throughput from the South Prairie Region assets driven by volumes returning to the system from alternative transportation sources, such as rail. Partially offsetting the increase in adjusted EBIT were higher business development costs not eligible for capitalization in the ﬁrst quarter of 2015, lower average tolls on the Olympic pipeline and higher property taxes relating to Toledo Pipeline in the third quarter of 2015. Eddystone Rail Legal Matter On February 2, 2017, Enbridge subsidiary Eddystone Rail Company, LLC, (Eddystone) ﬁled an action against several defendants in the United States District Court for the Eastern District of Pennsylvania. Eddystone alleges that the defendants transferred valuable assets from Eddystone’s counterparty in a maritime contract, so as to avoid outstanding obligations to Eddystone. Eddystone is seeking payment of compensatory and punitive damages in excess of US$140 million. Eddystone’s chances of success in connection with the above noted action cannot be predicted and it is possible that Eddystone may not recover any of the amounts sought. Business Risks The risks identiﬁed below are speciﬁc to the Liquids Pipelines business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. Asset Utilization Enbridge is exposed to throughput risk under the CTS on the Canadian Mainline and under certain tolling agreements applicable to other Liquids Pipelines assets, such as the Lakehead System. A decrease in volumes transported can directly and adversely affect revenues and earnings. Factors such as changing market fundamentals, capacity bottlenecks, operational incidents, regulatory restrictions, system maintenance and increased competition can all impact the utilization of Enbridge’s assets. Market fundamentals, such as commodity prices and price differentials, weather, gasoline price and consumption, alternative Feeder Pipelines and Other adjusted EBIT for the year ended energy sources and global supply disruptions outside of Enbridge’s December 31, 2016 was $196 million compared with $155 million control can impact both the supply of and demand for crude oil for the year ended December 31, 2015. The year-over-year increase and other liquid hydrocarbons transported on Enbridge’s pipelines. in adjusted EBIT primarily reﬂected new contributions from Southern In the second quarter of 2016, extreme wildﬁres in northeastern Access Extension which was placed into service in the fourth Alberta resulted in a temporary curtailment of oil sands production quarter of 2015. These positive contributions were partially offset from facilities in the vicinity of Fort McMurray, Alberta, resulting by a decrease in adjusted EBIT from Eddystone Rail, primarily in a negative impact on the Company’s adjusted EBIT and ACFFO attributable to market conditions which impacted volumes at as discussed above. However, the long-term outlook for Canadian the rail facility. Adjusted EBIT for the year ended December 31, 2016 crude oil production, particularly from western Canada, and also reﬂected lower contributions from Toledo Pipeline resulting from increasing United States domestic production indicates a growing reﬁnery turnarounds that negatively impacted volumes in the second source of potential supply of crude oil. and third quarters of 2016, as well as the absence of EBIT from the South Prairie Region assets in the month of December 2016. Feeder Pipelines and Other adjusted EBIT for the year ended December 31, 2015 was $155 million compared with $119 million for the year ended December 31, 2014. The increase in adjusted EBIT was attributable to higher earnings from Eddystone Rail While take-or-pay and similar contractual arrangements on certain systems serve to mitigate exposure to the risks noted above, under certain contracts, committed shippers are provided with relief from their take-or-pay payment obligations to the extent such shippers are unable to ship committed volumes on a pipeline solely as a result of Canadian Mainline apportionment. Management’s Discussion & Analysis 63 Enbridge seeks to mitigate utilization risks within its control. effect on the Company’s revenues and earnings. Delays in regulatory The market access expansion initiatives, which have had components approvals on projects such as the Company’s L3R Program, could placed into service over the past several years, and those currently result in cost escalations and construction delays, which also under development have and are expected to further reduce negatively impact the Company’s operations. capacity bottlenecks and enhance access to markets for customers. The Company also seeks to optimize capacity and throughput on its existing assets by working with the shipper community to enhance scheduling efficiency and communications, as well as makes continuous improvements to scheduling models and timelines to maximize throughput. Further to the day-to-day improvements sought by Enbridge, the Company is also undertaking the L3R Program, which upon completion, will support the safety and operational reliability of the overall system and enhance the ﬂexibility on the mainline system allowing the Company to further optimize throughput. Throughput risk is partially mitigated 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. by provisions in the CTS agreement, which allow Enbridge to adjust Renewal of Line 5 Easement the applicable L3R Program surcharge if volumes fall below deﬁned thresholds or to negotiate an amendment to the agreement in the event certain minimum threshold volumes are not met. Lastly, in February 2017, the Company acquired an interest in the Bakken Pipeline System, a growth project that will provide North Dakota producers enhanced access to premium light crude oil markets in both the eastern and western United States Gulf Coast. For further details and recent developments on this matter, refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Bakken Pipeline System (EEP). Operational and Economic Regulation On January 4, 2017, the Tribal Council of the Bad River Band of Lake Superior Tribe of Chippewa Indians (the Band) voted not to renew its interest in certain Line 5 easements through the Bad River Reservation. Line 5 is included within the Company’s mainline system. The Band’s resolution calls for decommissioning and removal of the pipeline from all Bad River lands and watershed. The Tribal Resolution may impact the Company’s ability to operate the pipeline on the Reservation. Since the Band passed the resolution, the parties have held discussions about the possibility of engaging in a facilitated mediation process, with the objective of resolving the Band’s concerns on a long-term basis. Operational regulation risks relate to failing to comply with applicable Competition 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 Competition may result in a reduction in demand for the Company’s services, fewer project opportunities or assumption of risk that results in weaker or more volatile ﬁnancial performance than expected. Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. Other competing carriers available to ship western Canadian liquid hydrocarbons to markets in Canada, the United States and internationally represent competition to the Company’s liquids pipelines network. Competition also arises from proposed pipelines that seek to access markets currently served by the Company’s liquids pipelines, such as proposed projects to the Gulf Coast regulations is the best approach to managing operational regulatory or eastern markets. Competition also exists from proposed projects risk, the potential remains for regulators to make unilateral decisions enhancing infrastructure in the Alberta regional oil sands market. 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, Lakehead System and other liquids pipelines are subject to the actions of various regulators, including the NEB and FERC, with respect to the tariffs and tolls of those operations. The changing or rejecting The Mid-Continent and Bakken systems also face competition from existing competing pipelines, proposed future pipelines and existing and alternative gathering facilities. Competition for storage facilities in the United States includes large integrated oil companies and other midstream energy partnerships. Additionally, volatile crude price differentials and insufficient pipeline capacity on either Enbridge or other competitor pipelines can make transportation of crude oil by rail competitive, particularly to markets not currently serviced by pipelines. of commercial arrangements, including decisions by regulators The Company believes that its liquids pipelines continue to provide on the applicable tariff structure or changes in interpretations attractive options to producers in the WCSB due to its competitive of existing regulations by courts or regulators, could have an adverse tolls and ﬂexibility through its multiple delivery and storage points. 64 Enbridge Inc. 2016 Annual Report Enbridge’s current complement of growth projects to expand market access and to enhance capacity on the Company’s pipeline system combined with the Company’s commitment to project execution is expected to further provide shippers reliable and long-term competitive solutions for oil transportation. The Company’s existing right-of-way for the mainline system also provides a competitive advantage as it can be difficult and costly to obtain rights of way for new pipelines traversing new areas. The Company also employs long-term agreements with shippers, which also mitigate competition risk by ensuring consistent supply to the Company’s liquids pipelines network. Foreign Exchange and Interest Rate Risk The CTS agreement for the Canadian Mainline exposes the Company to risks related to movements in foreign exchange rates and interest rates. Foreign exchange risk arises as the Company’s IJT under the CTS is charged in United States dollars. These risks have been substantially managed through the Company’s hedging program by using ﬁnancial contracts to ﬁx the prices of United States dollars and interest rates. Certain of these ﬁnancial contracts do not qualify for cash ﬂow hedge accounting and, therefore, the Company’s earnings are exposed to associated changes in the mark-to-market value of these contracts. Gas Distribution Earnings Before Interest and Income Taxes (millions of Canadian dollars) Enbridge Gas Distribution Inc. (EGD) Noverco Inc. (Noverco) Other Gas Distribution and Storage Adjusted earnings before interest and income taxes EGD – (warmer)/colder than normal weather EGD – employee severance cost adjustment Noverco – changes in unrealized derivative fair value loss Noverco – recognition of regulatory balances Noverco – asset impairment Earnings before interest and income taxes Adjusted EBIT from Gas Distribution was $494 million in 2016 compared with $446 million and $391 million in 2015 and 2014, respectively. EGD generated higher adjusted EBIT in 2016 primarily due to an increase in distribution charges arising from growth in EGD’s rate base, including customer growth. In 2016, adjusted EBIT from Other Gas Distribution and Storage reﬂected lower distribution revenues due to warmer weather in the New Brunswick region. Additional details on items impacting Gas Distribution EBIT include: • Noverco EBIT for 2016 included an asset impairment in relation to certain long-term assets not eligible for recovery through rates. • Noverco EBIT for 2016 included the recognition of regulatory assets in relation to employee future beneﬁts. 2016 2015 2014 393 53 48 494 (18) 10 (6) 17 (5) 492 342 53 51 446 15 6 (12) – – 455 305 45 41 391 48 – (7) – – 432 Gas Distribution (millions of Canadian dollars) 2 9 4 4 9 4 5 5 4 6 4 4 2 3 4 1 9 3 141 151 161 ■■ ■ GAAP EBIT ■■ ■ Adjusted EBIT 1 Effective January 1, 2016, the Company revised its reportable segments and reported Earnings before interest and income taxes for each reporting segment. The above information has reﬂected this change. Management’s Discussion & Analysis 65 Enbridge Gas Distribution Inc. Gas Distribution EGD is Canada’s largest natural gas distribution company and has been in operation for more than 160 years. It serves over two million customers in central and eastern Ontario and areas of northern New York State. EGD’s utility operations are regulated by the OEB and the New York State Public Service Commission. Incentive Rate Plan EGD’s 2016, 2015 and 2014 rates were set in accordance with parameters established by the customized IR Plan. The customized IR Plan was approved in 2014 by the OEB, with modiﬁcations, for 2014 through 2018, inclusive of the requested capital investment CANADA Gaz Métro Gaz Métro Gazifère Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas Enbridge Gas New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick New Brunswick amounts and an incentive mechanism providing the opportunity Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto to earn above the allowed ROE. Sarnia Sarnia St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas St. Lawrence Gas Enbridge Gas Enbridge Gas Distribution Distribution The customized IR Plan provides the methodology for establishing rates for the distribution of natural gas for a ﬁve-year period from 2014 through 2018. Within annual rate proceedings for 2015 through 2018, the customized IR Plan allows revenues and corresponding rates to be updated annually for select items including the rate of return to be earned on the equity component of its rate base. The OEB also approved the adoption of a new approach for determining net salvage percentages to be included within EGD’s approved depreciation rates, as compared with the traditional approach previously employed. The new approach results in lower net salvage percentages for EGD, and therefore lowers depreciation rates and future removal and site restoration reserves. UNIT ED STA TES UNIT ED STA TES OF A MERICA OF A MERICA For the year ended December 31, 2016, EGD’s rates were set according to the OEB approved settlement agreement in December 2015 and the ﬁnal rate order in May 2016. For the year ended December 31, 2015, EGD’s rates were set according to the OEB approved settlement agreement in April 2015 and the ﬁnal rate order in May 2015. For the year ended December 31, 2014, EGD’s rates were set by the OEB’s July 2014 decision, and subsequent August 2014 decision and rate order in the Company’s customized IR application. In order to align the interest of customers with the Company’s shareholders, the customized IR Plan includes an earnings sharing mechanism, whereby any return over the allowed rate of return for a given year under the customized IR Plan is to be shared equally with customers. For the years ended December 31, 2016, 2015 and 2014, EGD recognized $3 million subject to OEB approval, $7 million and $12 million, respectively, as a return of revenues to customers in relation to the earnings sharing mechanism. Enbridge Gas Distribution – Number of Active Customers (thousands) 2 3 0 2 , 5 6 0 2 , 8 9 0 2 , 9 2 ,1 2 8 5 1 , 2 Cap and Trade 12 13 14 15 16 Effective January 1, 2017, Ontario commenced a cap and trade program as part of changes intended to lower levels of GHG emissions across the province of Ontario. Under this program, there will be costs related to the GHG emissions from residential and commercial natural gas usage. The Government of Ontario has indicated the funds it collects through the cap and trade program will be allocated to other programs, such as energy conservation, aimed to reduce GHG emissions. The Government of Ontario requires EGD to acquire GHG allowances to cover the applicable emissions from its residential and commercial customers’ usage of natural gas, as well as from emissions from the delivery of natural gas to these customers. Under an interim rate order approved by the OEB, EGD has started to recover cap and trade compliance costs through rates beginning January 1, 2017. 66 Enbridge Inc. 2016 Annual Report 2016 2015 2014 393 (178) (14) 3 (3) 201 (13) 7 (2) 193 342 (153) (18) 4 5 180 11 4 (3) 192 305 (150) (10) – 13 158 36 – – 194 Results of Operations As EGD’s operations are rate-regulated and its revenues are directly impacted by items such as depreciation, ﬁnancing charges and current income taxes, the adjusted EBIT measure for EGD is less indicative of business performance. In light of the nature of the regulated model for EGD’s business, the following supplemental adjusted earnings information is provided to facilitate an understanding of EGD’s results from operations: EGD Earnings (millions of Canadian dollars) Adjusted earnings before interest and income taxes Interest expense Income taxes Adjusting items in respect of: Interest expense Income taxes Adjusted earnings EGD – (warmer)/colder than normal weather EGD – employee severance cost adjustment EGD – changes in unrealized derivative fair value loss Earnings attributable to common shareholders EGD adjusted earnings for the year ended December 31, 2016 were $201 million compared with $180 million for the year ended December 31, 2015. The year-over-year increase in adjusted earnings primarily reﬂected higher distribution charges arising from growth in EGD’s rate base, including customer growth. EGD adjusted earnings for the year ended December 31, 2015 were $180 million compared with $158 million for the year ended December 31, 2014. EGD’s higher adjusted earnings in 2015 were primarily attributable to an increase in distribution charges that resulted from an increased rate base, as well as customer growth during the year in excess of expectations embedded in rates. Noverco Enbridge owns an equity interest in Noverco through ownership of 38.9% of its common shares and an investment in preferred shares. Noverco is a holding company that owns approximately 71% of Gaz Métro Limited Partnership (Gaz Métro), a natural gas distribution company operating in the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in the province of Quebec and the state of Vermont. Noverco also holds, directly and indirectly, an investment in Enbridge common shares. A signiﬁcant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred share investments which are based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%. Results of Operations Noverco adjusted EBIT of $53 million for the year ended December 31, 2016 was comparable with adjusted EBIT of $53 million for the year ended December 31, 2015. Gaz Métro realized higher adjusted operating earnings for 2016 due to a stronger United States dollar, and growth in both its regulated and non-regulated rate base. This was offset by lower wind energy production, as well as lower preferred share dividend income, driven by a lower Government of Canada bond reference rate re-setting. In addition to these factors, there was a decrease in Noverco adjusted EBIT for the fourth quarter of 2016 compared with the fourth quarter of 2015, primarily reﬂecting higher adjusted EBIT in the fourth quarter of 2015 due to the timing of equity earnings adjustments between quarters. Management’s Discussion & Analysis 67 Noverco adjusted EBIT was $53 million for the year ended for another 25 years after that. The Province of New Brunswick December 31, 2015 compared with $45 million for the year ended also amended the laws governing gas distribution in the province December 31, 2014. The increase in year-over-year adjusted EBIT to, among other things, provide EGNB with the opportunity reﬂected stronger operating earnings from Gaz Métro due to a to recover through rates during the agreed upon franchise extension favourable Average Exchange Rate on Gaz Métro’s United States period up to $145 million of the deferred regulatory asset rendered based business and incremental contributions from new assets. unavailable by the 2012 legislative and regulatory changes. Of this Partially offsetting the higher adjusted EBIT was lower preferred amount, $100 million is to be recoverable at a ﬁxed rate of $4 million share dividend income based on lower yield of 10-year Government annually starting in the ﬁrst year of the franchise extension term of Canada bonds. Other Gas Distribution and Storage Other Gas Distribution includes natural gas distribution utility operations in Quebec and New Brunswick, the most signiﬁcant and the balance is recoverable throughout the future franchise term upon regulatory approval. While Enbridge considers the conditions of settlement and broader legislative changes enacted to achieve it as a favourable development for EGNB’s operating environment, EGNB’s recovery of the deferred regulatory asset over the future being EGNB which is wholly-owned and operated by the Company. franchise period is not guaranteed and remains subject to the EGNB operates the natural gas distribution franchise in the province usual operational and regulatory factors applicable to recovery of New Brunswick, has approximately 11,800 customers and is regulated by the New Brunswick Energy and Utilities Board (EUB). of deferred amounts. Business Risks Results of Operations Other Gas Distribution and Storage adjusted EBIT was $48 million for the year ended December 31, 2016 compared with $51 million for The risks identiﬁed below are speciﬁc to the Gas Distribution business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business the year ended December 31, 2015. The decrease in year-over-year Risks. adjusted EBIT primarily reﬂected lower distribution revenues due to warmer weather in the New Brunswick region in 2016. Economic Regulation Other Gas Distribution and Storage adjusted EBIT was $51 million for the year ended December 31, 2015 compared with $41 million for the year ended December 31, 2014. The increase in adjusted EBIT reﬂected the absence of a loss that EGNB incurred in 2014 under a contract to sell natural gas to the province of New Brunswick. Due to an abnormally cold winter in the ﬁrst quarter of 2014, costs associated with the fulﬁlment of the contract were higher than the revenues received. Excluding the impact of the above noted contract which expired in October 2014, EGNB adjusted EBIT increased slightly in 2015 due to higher distribution revenues. Enbridge Gas New Brunswick Inc. – Regulatory Matters The Company commenced two separate actions in 2012 and 2014, respectively, against the Government of New Brunswick in the New Brunswick courts. The ﬁrst action sought recovery of damages alleged to have arisen due to various breaches of the General Franchise Agreement with EGNB, under which EGNB operates in the province. The second action sought damages for improper extinguishment of a deferred regulatory asset that was eliminated from EGNB’s Consolidated Statements of Financial Position in 2012, due to legislative and regulatory changes enacted by the Government of New Brunswick in that year. The utility operations of Gas Distribution are regulated by the OEB and EUB among others. Regulators’ future actions may differ from current expectations, or future legislative changes may impact the regulatory environments in which Gas Distribution operates. To the extent that the regulators’ future actions are different from current expectations, the timing and amount of recovery or refund of amounts recorded on the Consolidated Statements of Financial Position, or that would have been recorded on the Consolidated Statements of Financial Position in absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded. The Company seeks to mitigate economic regulation risk. The Company retains dedicated professional staff and maintains strong relationships with customers, intervenors and regulators. The terms of rate negotiations are reviewed by the Company’s legal, regulatory and ﬁnance teams. The ﬁve-year customized IR Plan approved in 2014 provides a level of stability by having a long-term agreement with the OEB which allows EGD to recover its expected capital investments under the agreement, as well as an opportunity to earn above the OEB allowed ROE. Under the customized IR Plan, EGD is permitted to recover, with OEB approval, certain costs that were beyond management control, but that were necessary for the By agreement ﬁnalized on December 16, 2016, the parties fully maintenance of its services. The customized IR Plan also includes and ﬁnally settled both of the actions. EGNB’s franchise for gas a mechanism to reassess the customized IR Plan and return to cost distribution in New Brunswick was extended for 25 years beyond of service if there are signiﬁcant and unanticipated developments its original term ending in 2019, further extendable at EGNB’s option that threaten the sustainability of the customized IR Plan. 68 Enbridge Inc. 2016 Annual Report Environmental Regulation EGD’s workers, operations and facilities are subject to municipal, provincial and federal legislation which regulates the protection of the environment and the health and safety of workers. For the environment, this includes the regulation of discharges to air, land and water; the management and disposal of solid and hazardous 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. waste; and the assessment of contaminated sites. Failing to comply EGNB is also subject to natural gas cost risk as increases with regulations could expose EGD to ﬁnes or operating restrictions. in natural gas prices that cannot be fully recovered from customers In May 2016, the Government of Ontario passed legislation to establish a cap and trade program in the province of Ontario. Under the legislation, EGD is required to meet GHG compliance 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. obligations by purchasing emission allowances for EGD and its Volume Risk customers. In September 2016, the OEB issued its regulatory framework for the assessment of costs of natural gas utilities’ cap and trade activities, addressing regulatory requirements for implementation of cap and trade. In November 2016, EGD ﬁled its compliance plan with the OEB and also received approval of an interim rate order for the recovery of cap and trade compliance costs through rates beginning January 1, 2017. In 2016, EGD was required to report 2015 GHG emissions to the Ontario Ministry of Environmental and Climate Change from combustion sources only in Ontario, and all reported data was veriﬁed by a third party. There were no issues identiﬁed for the 2015 reporting year. EGD monitors developments and attends external stakeholder consultations in Ontario. EGD utilizes a carbon data management system to help with the data capture and mandatory and voluntary reporting needs of EGD. EGD continues to publicly report its GHG emissions and will continue to develop internal procedures to identify operational related GHG reductions. In July 2016, EGD received $58 million from the Government of Ontario for the purpose of carrying out the Green Investment Fund (GIF) program. The purpose of the GIF program is to reduce GHG emissions in the residential sector. EGD’s use of the funds is limited to eligible expenditures for the purpose of executing the program. There is no earnings impact related to the GIF program and any unspent funds will be returned to the Government of Ontario at the expiry of the agreement on May 31, 2019, or sooner if the Government of Ontario elects to terminate the agreement at any time prior to its expiration date. Natural Gas Cost Risk EGD’s regulated business does not proﬁt from the sale of natural gas nor is it at risk for the difference between the actual cost of natural gas purchased and the price approved by the OEB for inclusion in distribution rates. This difference is deferred as a receivable from or payable to customers until the OEB approves its refund or collection. EGD monitors the balance and its potential impact on customers and may request interim rate relief to recover Since customers are billed on a volumetric basis, EGD’s ability to collect its total revenue requirement (the cost of providing service) depends on achieving the forecast distribution volume established in the rate-making process. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Weather is a signiﬁcant driver of delivery volumes, given that a signiﬁcant portion of EGD’s customer base uses natural gas for space heating. Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continue to place downward pressure on consumption. In addition, conservation efforts by customers may further contribute to a decline in annual average consumption. Sales and transportation of gas for customers in the residential and small commercial sectors account for approximately 80% of total distribution volume. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Customer additions from all market sectors are important as continued expansion adds to the total consumption of natural gas. Even in those circumstances where EGD attains its total forecast distribution volume, it may not earn its expected ROE due to other forecast variables, such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector. EGNB is also subject to volume risk as the impact of weather conditions on demand for natural gas could result in earnings ﬂuctuations. EGD remains at risk for the actual versus forecast large volume contract commercial and industrial volumes; however, general service volume risk is mitigated for both ratepayers and EGD through a deferral account. Management’s Discussion & Analysis 69 Gas Pipelines and Processing Earnings Before Interest and Income Taxes (millions of Canadian dollars) Aux Sable Alliance Pipeline Vector Pipeline Canadian Midstream Enbridge Offshore Pipelines (Offshore) US Midstream Other Adjusted earnings before interest and income taxes Aux Sable – asset impairment loss Aux Sable – accrual for commercial arrangements Alliance Pipeline – changes in unrealized derivative fair value gains/(loss) Alliance Pipeline – derecognition of regulatory balances Offshore – gain on sale of non-core assets US Midstream – changes in unrealized derivative fair value gains/(loss) US Midstream – goodwill impairment loss US Midstream – assets impairment loss US Midstream – loss on disposal of non-core assets US Midstream – make-up rights adjustment US Midstream – transfer of contracts Earnings/(loss) before interest and income taxes 2016 2015 2014 (2) 184 31 107 58 5 (17) 366 (37) – 10 – – (149) – (14) (4) (1) – 171 (3) 151 28 87 14 73 (14) 336 – (30) (15) 8 6 (62) (440) (20) – 1 (13) (229) 45 135 24 60 12 30 (13) 293 – – (6) – 22 180 – (18) – (4) – 467 Adjusted EBIT from Gas Pipelines and Processing was $366 million in 2016 compared with adjusted EBIT of $336 million and $293 million in 2015 and 2014. The year-over-year increase in adjusted EBIT was driven primarily by operational efficiencies achieved by Alliance Pipeline, Gas Pipelines and Processing (millions of Canadian dollars) higher adjusted EBIT from Offshore reﬂecting contributions from Heidelberg Pipeline which was placed into service in January 2016, as well as increase in adjusted EBIT from Canadian Midstream reﬂecting contributions from the Tupper Plants acquired on April 1, 2016. Partially offsetting these increases were unfavourable market conditions in US Midstream in 2016, resulting in a year-over-year decrease in adjusted EBIT from lower volumes due to reduced drilling by producers. Additional details on items impacting Gas Pipelines and Processing Services EBIT include: • Aux Sable EBIT for 2016 included an asset impairment charge related to certain underutilized assets at Aux Sable US’ NGL extraction and fractionation plant. • US Midstream EBIT for 2015 included a goodwill impairment charge related to the Company’s United States natural gas and NGL businesses due to a prolonged decline in commodity prices which has reduced producers’ expected drilling programs and negatively impacted volumes on the Company’s natural gas and NGL systems. • US Midstream EBIT for each period reﬂected changes in unrealized fair value gains and losses on derivative ﬁnancial instruments used to risk manage commodity price exposures. • US Midstream EBIT for 2016 reﬂected asset impairment charges in relation to certain non-core trucking assets that the Company sold in the third quarter of 2016. • US Midstream EBIT for 2015 and 2014 reﬂected asset impairment charges in relation to a non-core propylene pipeline asset, following ﬁnalization of a contract restructuring with the primary customer. 7 6 4 3 9 2 6 6 3 6 3 3 1 7 1 ) ) 9 9 2 2 2 2 ( ( 141 151 161 ■ GAAP EBIT ■■ ■■ ■ Adjusted EBIT 1 Effective January 1, 2016, the Company revised its reportable segments and reported Earnings before interest and income taxes for each reporting segment. The above information has reﬂected this change. 70 Enbridge Inc. 2016 Annual Report Gas Pipelines and Processing C ANADA Calgary Calgary Superior Superior Montreal Montreal UNITED STATES UNITED STATES OF AMERICA OF AMERICA Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Cushing Cushing New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans New Orleans M E X I C 0 Assets in Operation Gas Plants in Operation Management’s Discussion & Analysis 71 Aux Sable Enbridge owns a 42.7% interest in Aux Sable US and Aux Sable Midstream US, and a 50% interest in Aux Sable Canada (together, Aux Sable). Aux Sable US owns and operates an NGL extraction and fractionation plant at Channahon, Illinois, outside Chicago, near the terminus of Alliance Pipeline. The plant extracts NGL from the liquids-rich natural gas transported on Alliance Pipeline as necessary for Alliance Pipeline to meet gas quality speciﬁcations of downstream transmission and distribution companies and to take advantage of positive fractionation spreads. The fractionation facilities at the Channahon Plant were expanded in 2016 in order to handle the increasing NGL content of the Alliance Pipeline’s gas stream. was received in connection with this potential exceedance. Aux Sable engaged in discussions with the EPA to evaluate the impacts and ultimate resolution of these issues, including with respect to a draft Consent Decree, and those discussions are continuing. The Consent Decree, when ﬁnalized, is not expected to have a material impact. On October 14, 2016, an amended claim was ﬁled against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable ﬁled a Statement of Defence with respect to this claim. While the ﬁnal outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on the Company’s consolidated ﬁnancial position or results of operations. Aux Sable US sells its NGL production from the base plant to Results of Operations a single counterparty under a long-term contract. Aux Sable receives a ﬁxed annual fee and a share of any net margin generated from the business in excess of speciﬁed natural gas processing margin thresholds (the upside sharing mechanism). In addition, Aux Sable is compensated for all operating and maintenance costs for the base plant, and subject to certain limits, costs incurred to source feedstock supply and capital costs associated with its facilities. The counterparty supplies all make-up gas and fuel gas requirements for the base plant. The contract is for an initial term of 20 years, expiring March 31, 2026, and may be extended by mutual agreement for 10-year terms. NGL production associated with the expanded fractionation facilities is sold by a third party marketer, on behalf of Aux Sable, under a three year contract. Aux Sable also owns facilities upstream of Alliance Pipeline that facilitate deliveries of liquids-rich gas volumes into the pipeline for further processing at the Aux Sable plant. These facilities include the Palermo Conditioning Plant and the Prairie Rose Pipeline in the Bakken area of North Dakota, owned and operated by Aux Sable Midstream US; and Aux Sable Canada’s interests in the Montney area of British Columbia, comprising the Septimus Pipeline and a 22% interest it acquired effective October 1, 2015 in the Septimus and Wilder Gas Plants, in exchange for its previously held 50% ownership interest in the Septimus Plant. Aux Sable Canada has contracted capacity on the Septimus Pipeline and the Septimus and Wilder Gas Plants to a producer under a 10-year take-or-pay contract, which provides for a return on and of invested capital. Actual operating costs are recovered from the producer. In 2016, the Palermo Gas Plant and the Prairie Rose Pipeline were contracted to producers under either take-or-pay, area dedication or fee for service contracts, with contract terms out to 2020. Gas processed at the Palermo Plant in 2016 averaged 53 mmcf/d. Throughput on the Prairie Rose Pipeline in 2016 averaged 100 mmcf/d. In addition, revenues are earned by Aux Sable based on a sharing of available NGL margin with producers. In September 2014, Aux Sable US received a Notice and Finding Aux Sable reported adjusted loss before interest and taxes of $2 million for the year ended December 31, 2016 comparable with adjusted loss before interest and taxes of $3 million for the year ended December 31, 2015. Aux Sable’s operations include both a Canadian and United States component. Within Aux Sable adjusted loss before interest and taxes for the year ended December 31, 2016 was US$2 million from its United States’ operations compared with adjusted EBIT of US$4 million for the year ended December 31, 2015. The slight year-over-year decrease in Aux Sable adjusted loss before interest and taxes was the result of a reduction in gas purchase costs and overhead cost savings within the Canadian business, and lower NGL transport costs within the North Dakota business. These favourable variances were partially offset by higher NGL feedstock costs at the Aux Sable US plant associated with an increase in Rich Gas Premium (RGP) contract volumes. There were no earnings contributions from the upside sharing mechanism in either 2016 or 2015 as a result of low fractionation margins. Aux Sable also reported lower adjusted loss before interest and income taxes for the fourth quarter of 2016 compared with the fourth quarter of 2015, primarily due to lower quarter-over-quarter feedstock supply costs. Aux Sable reported adjusted loss before interest and taxes of $3 million for the year ended December 31, 2015 compared with adjusted EBIT of $45 million for the year ended December 31, 2014. Within Aux Sable adjusted EBIT for the year ended December 31, 2015 was US$4 million from its United States’ operations compared with US$30 million for the year ended December 31, 2014. Lower fractionation margins resulting from a weaker commodity price environment, absence of contributions from the upside sharing mechanism, costs associated with feedstock supply and the loss of a producer processing contract at the Palermo Conditioning Plant were the main drivers behind the decreases in adjusted EBIT in 2015 compared with 2014. Aux Sable Feedstock Supply of Violation (NFOV) from the United States EPA for alleged violations Aux Sable secures NGL feedstock for its Channahon Plant primarily of the Clean Air Act related to the Leak Detection and Repair program, through RGP contracts with producers, with varying terms ranging up and related provisions of the Clean Air Act permit for Aux Sable’s to a maximum of seven years. RGP contracts provide for producers Channahon, Illinois facility. As part of the ongoing process of and Aux Sable to share in the value of the liquids-rich natural gas responding to the September 2014 NFOV, Aux Sable discovered (both residual dry gas and extracted NGL) transported on the Alliance what it believed to be an exceedance of currently permitted limits for Pipeline. Effective December 1, 2015, Canadian producers contracted Volatile Organic Material. In April 2015, a second NFOV from the EPA for ﬁrm transportation service under Alliance Pipeline’s New Service 72 Enbridge Inc. 2016 Annual Report Framework, and either transport volumes to Aux Sable’s Channahon Plant or to the new Alliance Trading Point, notionally located on Alliance Pipeline Canada. Aux Sable purchases RGP gas volumes delivered to the Alliance Trading Point and through corresponding gas sales contracts, assignments or other arrangements with counterparties, Aux Sable facilitates the transport of purchased gas to the Channahon Plant. For further details on the Alliance Pipeline recontracting, refer to Gas Pipeline and Processing – Alliance Pipeline – Alliance Pipeline New Services Framework. Heat Content Management Aux Sable is under contract with Alliance Pipeline to provide heat content management services to ensure natural gas exiting the Aux Sable Channahon Plant meets gas quality speciﬁcations of downstream transmission and distribution companies, including NGL content (i.e. heat content). Aux Sable monitors the quality of the plant’s outlet gas stream on a continuous basis. In 2016, Aux Sable completed an expansion of its fractionation capacity in order to handle increasing volumes of NGLs delivered to the plant. Aux Sable is assessing various options with respect to heat content management as the heat content of the natural gas delivered by Alliance Pipeline is expected to increase in the future. Business Risks The risks identiﬁed below are speciﬁc to Aux Sable. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks. Commodity Price Risk Aux Sable’s NGL margin earned through the upside sharing mechanism is subject to commodity price risk arising from the price differential between the cost of natural gas and the value achieved from the sale of extracted NGL after the fractionation process. Aux Sable is also subject to the value of natural gas on the Alliance Pipeline supplied by certain of its RGP producers. To mitigate this natural gas supply risk, Aux Sable has entered into a variety of contracts with counterparties. Commodity price risk created from Aux Sable’s RGP contracts and through the upside sharing mechanism is closely monitored and must comply with its formal risk management policies that are consistent with the Company’s risk management practices. These risks may be mitigated by Aux Sable or through the Company’s risk management activities. Asset Utilization A decrease in gas volumes or a decrease in the NGL content of the gas stream delivered by Alliance Pipeline to the Aux Sable plant can directly and adversely affect margins earned. Aux Sable is well-positioned to offer RGP contracts, when necessary, to producers within the liquids-rich Montney, Duvernay and Bakken plays that are located in close proximity to Alliance Pipeline to mitigate these risks. Alliance Pipeline The Alliance Pipeline, which includes both Alliance Pipeline Canada and Alliance Pipeline US, consists of approximately 3,000 kilometres (1,864 miles) of integrated, high-pressure natural gas transmission pipeline and approximately 860 kilometres (534 miles) of lateral pipelines and related infrastructure. Alliance Pipeline transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area in North Dakota to the Alliance Chicago gas exchange hub downstream of the Aux Sable NGL extraction and fractionation plant at Channahon, Illinois. Alliance Pipeline US and Alliance Pipeline Canada have annual ﬁrm service shipping capacity to deliver 1.455 billion cubic feet per day (bcf/d) and 1.325 bcf/d, respectively. Natural gas transported on Alliance Pipeline downstream of the Aux Sable plant can be delivered to two local natural gas distribution systems in the Chicago area and ﬁve interstate natural gas pipelines, providing shippers with access to midwest and eastern natural gas markets. Alliance Pipeline— Average Throughput Volumes (millions of cubic feet per day) 2 8 6 , 1 6 5 5 , 1 5 4 6 , 1 8 8 4 , 1 8 6 6 , 1 2 2 3 3 5 5 , , 1 1 14 15 16 ■■ ■ Alliance Pipeline Canada ■■ ■ Alliance Pipeline US Management’s Discussion & Analysis 73 Alliance Pipeline New Services Framework of 10.88%. In addition, Alliance Pipeline US negotiated non-renewal Effective December 1, 2015, Alliance Pipeline commenced operations under its New Services Framework. Prior to December 1, 2015, Alliance Pipeline successfully re-contracted its annual ﬁrm service capacity with an average contract length of approximately ﬁve years. charges that were an exit fee for shippers that did not elect to extend their transportation contracts. The initial term of the TSAs expired in December 2015, with the exception of a small proportion of shippers that elected to extend their contracts beyond 2015. As part of the Canadian portion of the New Services Framework, Results of Operations the NEB granted pricing discretion for interruptible transportation and seasonal ﬁrm service with all associated revenues accruing to Alliance Pipeline Canada. The FERC, as part of its acceptance of Alliance Pipeline US’ New Services Framework, set all issues related to the proposed elimination of Authorized Overrun Service and Interruptible Transportation revenue crediting, and the maintenance of Alliance Pipeline US’ existing recourse rates, for hearing. In 2016, the FERC expanded the issues set for hearing to include aspects of the Alliance Pipeline US tariff that relate to liquids extraction requirements. The FERC approved Alliance Pipeline US’ negotiated rate contracts, which are not set for hearing. Throughout 2016, Alliance Pipeline US conducted settlement hearings with all interested parties, which culminated in the certiﬁcation of a contested settlement issued to the FERC Commissioners on September 6, 2016, by a FERC ALJ. No Alliance Pipeline US customer contested the settlement. On December 15, 2016, the FERC Commissioners approved essentially all aspects of the contested settlement, except for the liquids extraction matter, which has been set for hearing, with any outcomes to be effective on a prospective basis. Alliance Pipeline has accepted the approved portions of the FERC Commissioners’ decision and is seeking rehearing of the decision regarding liquids extraction. Pursuant to the New Services Framework, Alliance Pipeline retains exposure to potential variability in revenues generated from market based services provided beyond contracted annual ﬁrm transport service, as well as certain future costs. As such, the majority of Alliance Pipeline’s operations no longer meet all Alliance Pipeline reported adjusted EBIT of $184 million for the year ended December 31, 2016, which represents EBIT from the Company’s 50% equity investment in Alliance Pipeline, compared with adjusted EBIT of $151 million for the year ended December 31, 2015. The year-over-year increase in adjusted EBIT was primarily due to lower operating costs and lower depreciation expense as a result of an extension to the useful life of the pipeline assets. Alliance revenues were lower in 2016 resulting from the New Services Framework that commenced in the fourth quarter of 2015; however, earnings from the New Services Framework beneﬁtted from strong demand for seasonal ﬁrm service. These positive effects were partially offset by the absence of the 2015 non-renewal fees for Alliance Pipeline US. Alliance Pipeline reported adjusted EBIT of $151 million for the year ended December 31, 2015 compared with adjusted EBIT of $135 million for the year ended December 31, 2014. This increase in adjusted EBIT was attributable to lower operating costs, a stronger United States dollar and strong demand in December 2015 for interruptible service under its New Services Framework. These increases were partially offset by a shutdown of Alliance Pipeline Canada for six days in August 2015 after an amount of hydrogen sulﬁde entered its mainline pipeline through an upstream operator, which resulted in Alliance Pipeline issuing demand charge credits to its shippers. Business Risks The risks identiﬁed below are speciﬁc to Alliance Pipeline. General risks that affect the entire Company are described under Risk of the criteria required for the continued application of rate-regulated Management and Financial Instruments – General Business Risks. accounting treatment. Alliance Pipeline Transportation Services Agreements Asset Utilization Currently, natural gas pipeline capacity out of the WCSB exceeds Prior to December 1, 2015, Alliance Pipeline Canada had transportation supply. Alliance Pipeline to date has been relatively unaffected by this service agreements (TSAs) with shippers for substantially all excess capacity environment as Alliance Pipeline is situated in the of its available ﬁrm transportation capacity. The TSAs were designed growing Montney, Duvernay and Bakken areas and was successfully to provide toll revenues sufficient to recover prudently incurred costs recontracted. Alliance Pipeline is also the only liquids-rich gas export of service, including operating and maintenance, depreciation, pipeline within the WCSB. Further, Alliance Pipeline accesses large an allowance for income tax, costs of indebtedness and an allowed natural gas markets and, following extraction and fractionation ROE of 11.26% after-tax, based on a deemed 70/30 debt-to-equity at the Aux Sable NGL extraction and fractionation plant, delivers ratio. Alliance Pipeline US had similar TSAs which allowed for NGL to growing NGL markets. As noted above, Alliance Pipeline’s the recovery of the cost of service, which included operating and New Services Framework also allows for the provision of services maintenance costs, the cost of ﬁnancing, an allowance for income beyond annual ﬁrm transport service, at market rates, further tax, an annual allowance for depreciation and an allowed ROE supporting asset utilization. 74 Enbridge Inc. 2016 Annual Report Competition Alliance Pipeline faces competition for pipeline transportation services to the Chicago area from both existing pipelines and proposed pipeline projects from existing and new gas developments throughout North America. Any new or upgraded pipelines could either allow shippers greater access to natural gas markets or offer natural gas transportation services that are more desirable than those provided by Alliance Pipeline because of location, facilities or other factors. In addition, any new, existing, or upgraded pipelines could charge tolls or rates or provide transportation services to locations that result in greater net proﬁt for shippers, with the effect of reducing future supply for Alliance Pipeline. The ability of Alliance Pipeline to cost-effectively transport liquids-rich gas and its proximity to the liquids-rich Montney, Duvernay and Bakken plays serve to enhance its competitive position. Economic Regulation Alliance Pipeline is subject to regulation by the NEB in Canada and the FERC in the United States. Under the New Services Framework, effective December 1, 2015, Alliance Pipeline has contracted with shippers under terms as approved by the NEB in Canada and the FERC in the United States. Firm service tolls are ﬁxed for the duration of the contracts’ terms. Vector Pipeline Vector adjusted EBIT for the year ended December 31, 2015 was $28 million compared with $24 million for the year ended December 31, 2014. Within Vector adjusted EBIT for the year ended December 31, 2015 was US$20 million (2014 – US$18 million) from its United States’ operations. Excluding the impact of foreign exchange translation to Canadian dollars, Vector adjusted EBIT for the year ended December 31, 2015 was comparable to the corresponding 2014 period. The positive effects of lower operating expenses were offset by lower year-over-year transportation revenues as unusually high demand for natural gas transport was experienced during abnormal winter weather conditions in the ﬁrst quarter of 2014. The slight increase in EBIT was due to a stronger United States dollar compared with the Canadian dollar. EBIT from the United States portion of Vector was translated at a higher Average Exchange Rate in 2015 compared with 2014 resulting in the overall increase in Vector adjusted EBIT in 2015. Transportation Contracts Vector’s total long haul capacity was fully contracted under ﬁrm service agreements at December 31, 2016. Long and short haul transportation service on the U.S segment of the system is contracted with shippers under a combination of both FERC approved negotiated rate service agreements and FERC tariff recourse rate service agreements. In 2016, the remaining initial long-term ﬁrm service shippers, Vector, which includes both the Canadian and United States portions representing 255 mmcf/d, restructured their agreements and of the pipeline system, consists of 560 kilometres (348 miles) extended their terms to 2020 and beyond. There are now no more of mainline natural gas transmission pipeline between the Chicago, initial long-term contracts with early termination or annual extension Illinois hub and a storage complex at Dawn, Ontario. Vector’s primary rights. sources of supply are through interconnections with Alliance Pipeline, Northern Border Pipeline and Guardian Pipeline in Joliet, Illinois. Vector has the capacity to deliver a nominal 1.3 bcf/d and in 2016 it operated at or near capacity. The Company provides operating services to and holds a 60% joint venture interest in Vector. Results of Operations Vector adjusted EBIT for the year ended December 31, 2016 was $31 million compared with adjusted EBIT of $28 million for the year ended December 31, 2015. Vector’s operations include a Canadian In late 2014 and early 2015, Vector signed precedent agreements with both the proposed NEXUS Pipeline (Nexus) project and Energy Transfer Partners L.P.’s Rover Pipeline (Rover) project, to provide transportation service to the Dawn natural gas market hub. The Rover project received FERC approval on February 2, 2017 and is expected to commence deliveries into Vector in late 2017. The Nexus project is expected to receive FERC approval later in 2017, the timing of which will delay the start of construction, thereby delaying initial deliveries into Vector until the second half of 2018. and United States component. Within Vector adjusted EBIT for Transportation service on Vector is provided through a number the year ended December 31, 2016 was US$21 million from its United of different forms of service agreements, including Firm Transportation States’ operations compared with adjusted EBIT of US$20 million for Service, Interruptible Transportation Service and Backhaul Service. the year ended December 31, 2015. Excluding the impact of foreign Vector is an interstate natural gas pipeline with FERC and NEB exchange translation to Canadian dollars, Vector adjusted EBIT, approved tariffs that establish the rates, terms and conditions which represents EBIT from the Company’s equity investment in governing its service to customers. On the United States portion Vector, was slightly higher for the year ended December 31, 2016 of Vector, maximum tariff rates are determined using a cost of service compared with the year ended December 31, 2015. The positive methodology and maximum tariff changes may only be implemented effect of lower interest costs due to a declining debt balance, upon approval by the FERC. For 2016, the FERC-approved maximum more than offset lower year-over-year transportation revenues. tariff rates included an underlying weighted average after-tax ROE Initial long-haul transportation contracts terminated in 2016 component of 12.75%. On the Canadian portion, Vector is required as expected and capacity was re-contracted at lower market to ﬁle its negotiated tolls calculation with the NEB on an annual basis. based rates. Tolls are calculated on a levelized basis that include a rate of return incentive mechanism based on construction costs and are subject to a rate cap. In 2016, maximum tolls on the Canadian portion include an ROE component of 10.48% after-tax. Management’s Discussion & Analysis 75 Business Risks Canadian Midstream 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. Asset Utilization Vector has been minimally impacted by the excess natural gas supply environment that exists throughout North America, mainly as a result of its long-term ﬁrm service contracts. Vector has entered into precedent agreements to provide transport service to both the Rover and Nexus proposed pipeline projects that will extend back to the Marcellus/Utica supply basin. Rover is expected to commence deliveries into Vector in late 2017, and Nexus in 2018. Once both projects are in service, these arrangements will effectively ﬁll all available delivery capacity to Dawn, Ontario from current contract roll-offs scheduled through 2019. Current ﬁrm service contracts that amount to approximately 60% of long haul capacity are scheduled to expire during 2017 and 2018. Competition Vector faces competition to transport natural gas into Ontario, Canada and other eastern markets from primarily the Marcellus supply region, which may reduce Vector deliveries sourced from its traditional interconnected pipelines in the United States Midwest. Vector manages this risk by focusing on developing long-term relationships with its customers and by providing them value added services. In addition, as discussed above, Vector is expected to commence ﬁrm service transport based on precedent agreements with respect to the Rover Pipeline and NEXUS Pipeline projects. Vector will reach its eastern delivery capacity once these projects are in service. Economic Regulation The United States portion of Vector is subject to regulation by the FERC. If tariff rates are protested, the timing and amount of any recovery or refund of amounts recorded on the Consolidated Statements of Financial Position could be different from the amounts that are eventually recovered or refunded. In addition, future proﬁtability of the entities could be negatively impacted. At December 31, 2016, Canadian Midstream consisted of the wholly-owned Tupper Plants located within the Montney shale play in northeastern British Columbia, the Company’s 71% interest in the Cabin Gas Plant (Cabin) located 60 kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin, as well as interests in the Pipestone and Sexsmith gathering systems (together, Pipestone and Sexsmith). The Company has almost 100% interest in Pipestone and the primary producer and operator of Pipestone holds a nominal 0.01% interest. The Company also has varying interests (55% to 100%) in Sexsmith and its related sour gas gathering, compression and NGL handling facilities, located in the Peace River Arch region of northwest Alberta. Enbridge is the operator of the Tupper Plants and Cabin. The Canadian Midstream investments are underpinned by 20-year take-or-pay contracts with producers. Return on and of capital is based on the actual costs to purchase or construct the facilities. The Company is not impacted by throughput volumes; however, the Company shares in revenues obtained from available capacity sold to third parties or on volumes that exceed producer take-or-pay levels. Operating costs are passed through to producers. In April 2016, Enbridge acquired the Tupper Plants as described under Growth Projects – Commercially Secured Projects. The Tupper Plants are designed to process low hydrogen sulﬁde natural gas and remove a modest level of NGL in order to meet downstream natural gas pipeline speciﬁcations. Phase 1 of Cabin is currently 98% completed. Cabin producers are expected to request the Company to commission and start-up Phase 1 once the natural gas price recovers to a more economic level to support the Horn River Basin’s dry gas production. Phase 2 construction is approximately 40% complete and is in preservation mode awaiting producer’s requests for completion. In December 2012, the Company started earning fees on its total investment made to date on both Phases 1 and 2. Results of Operations Canadian Midstream adjusted EBIT was $107 million for the year ended December 31, 2016 compared with adjusted EBIT of $87 million for the year ended December 31, 2015. The increase in year-over-year adjusted EBIT reﬂected contributions from the Tupper Plants following their acquisition on April 1, 2016. Contributions from the Company’s investment in Cabin, Pipestone and Sexsmith were comparable year-over-year. Canadian Midstream adjusted EBIT was $87 million for the year ended December 31, 2015 compared with adjusted EBIT of $60 million for the year ended December 31, 2014. Higher adjusted EBIT reﬂected an increase in take-or-pay fees on the Company’s investment in Cabin, Pipestone and Sexsmith. Pipestone adjusted EBIT also increased as a result of volumes that exceeded take-or-pay levels and due to a full year of incremental adjusted EBIT from the ﬁnal phase placed into service in June 2014. 76 Enbridge Inc. 2016 Annual Report Business Risks The risks identiﬁed below are speciﬁc to Canadian Midstream. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. Asset Utilization The Tupper Plants are located within the core of the Montney shale play, which continues to be developed by a number of producers. Although this area of the Montney contains a lower level of NGL content than others, production is supported by strong economics, the result of high initial production rates, ultimate recoveries and predictable low drilling and completion costs, making it one of the most competitive natural gas production regions in North America. Offshore adjusted EBIT was $14 million for the year ended December 31, 2015 compared with adjusted EBIT of $12 million for the year ended December 31, 2014. Excluding the impact of foreign exchange translation to Canadian dollars, Offshore adjusted EBIT of US$11 million for the year ended December 31, 2015 was comparable with US$12 million for the year ended December 31, 2014. Adjusted EBIT for both years reﬂected persistent weak gas volumes due to decreased production in the Gulf of Mexico. For the year ended December 31, 2015, Offshore incurred losses from equity investments in certain joint venture pipelines which were offset by contributions from the Jack St. Malo portion of WRGGS that was completed in December 2014. Finally, the higher adjusted EBIT also reﬂected the favourable impact of translating United States dollar earnings at a higher Average Exchange Rate in 2015. Cabin is located in the proliﬁc Horn River Basin, one of the largest Transportation Contracts gas shale plays in North America. The current low gas price The primary shippers on the Offshore systems are producers who environment has slowed development due to the remote location execute life-of-lease commitments in connection with transmission and the lack of NGL content to supplement producer economics. and gathering service contracts. In exchange, Offshore provides Accelerated development of the Horn River is expected to be ﬁrm capacity for the contract term at an agreed upon rate. The ﬁrm primarily tied to the development of LNG exports currently being capacity made available generally reﬂects the lease’s maximum pursued by Cabin producers. The nearby Cordova Embayment and sustainable production. The transportation contracts allow the Liard Basin share similar characteristics as the Horn River; however, shippers to deﬁne a maximum daily quantity over the expected they are at an earlier stage of development. production life. Some contracts have minimum throughput volumes Pipestone and Sexsmith are located within the liquids-rich Peace River Arch region which has seen signiﬁcant development by area producers. In 2016, throughput volumes exceeded take-or-pay levels. Enbridge Offshore Pipelines Offshore is comprised of 11 active natural gas gathering and FERC-regulated transmission pipelines and two active oil pipelines, that are subject to ship-or-pay criteria, but also provide the shippers with ﬂexibility, subject to advance notice criteria, to modify the projected maximum daily quantity schedule to match current delivery expectations. The majority of long-term contracts have ﬁxed transport rates, with revenue generation directly tied to actual production deliveries. Some of the systems operate under a cost-of- service methodology, including certain lines under FERC regulation. including the Heidelberg Pipeline that was placed in service in The business model to be utilized for the WRGGS, Big Foot Pipeline, January 2016. These pipelines are located in four major corridors Heidelberg Pipeline and Stampede Pipeline projects differs from in the Gulf of Mexico, extending to deepwater developments, and the historic model. These new projects have a base level return include almost 2,100 kilometres (1,300 miles) of underwater pipe that is locked in through either ship-or-pay commitments or ﬁxed and onshore facilities with total capacity of approximately 6.5 bcf/d. demand charge payments. If volumes meet or exceed a producer’s Results of Operations anticipated levels, the return on these projects may increase. In addition, Enbridge has minimal capital cost risk on these projects Offshore adjusted EBIT was $58 million for the year ended and commercial agreements continue to contain life-of-lease December 31, 2016 compared with adjusted EBIT of $14 million commitments. The WRGGS and Big Foot Pipeline project agreements for the year ended December 31, 2015. Excluding the impact of provide for recovery of actual capital costs to complete the project foreign exchange translation to Canadian dollars, Offshore adjusted in fees payable by producers over the contract term. The Stampede EBIT for the year ended December 31, 2016 was US$44 million Pipeline project provides for a capital cost risk sharing mechanism compared with US$11 million for the year ended December 31, 2015. whereby Enbridge is exposed to a portion of the capital costs The year-over-year increase in Offshore adjusted EBIT primarily in excess of an agreed upon target. Conversely, Enbridge can reﬂected contributions from Heidelberg Pipeline which was placed recover in fees from producers a portion of the capital cost savings into service in January 2016 and an increase in volumes in the below the agreed upon target. Adjustments are allowed for certain Mississippi Canyon Gas Pipeline in the ﬁrst half of 2016, partially of the Heidelberg Pipeline’s project variables that impact its cost, offset by a decrease in volumes in the Garden Banks Gas Pipeline with Enbridge bearing the residual capital cost risk after these in the second half of 2016. Finally, the higher year-over-year adjusted adjustments have been applied. EBIT also reﬂected the favourable impact of translating United States dollar earnings at a higher Average Exchange Rate in 2016. Management’s Discussion & Analysis 77 Business Risks The risks identiﬁed below are speciﬁc to Offshore. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. Asset Utilization A decrease in gas volumes transported by Offshore natural gas The occurrence of hurricanes in the Gulf of Mexico increases the cost, associated deductibles and availability of insurance coverage and as a result, the Company does not carry windstorm insurance coverage. Enbridge facilities are engineered to withstand hurricane forces and regular monitoring of extreme weather allows for timely evacuation of personnel and shutdown of facilities; however, damages to assets or injuries to personnel may still occur. pipelines can directly affect revenues and EBIT. Low natural gas US Midstream 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 US Midstream consists of the Anadarko, East Texas, North Texas and Texas Express NGL systems, which include natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. In addition, US Midstream has rail and liquids marketing operations. Enbridge’s ownership interest in US Midstream, held through EEP, was 19.0% as at December 31, 2016 (December 31, 2015 – 19.2%). Results of Operations 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 US Midstream adjusted EBIT was $5 million for the year ended December 31, 2016 compared with $73 million for the year ended December 31, 2015. Excluding the impact of foreign exchange translation to Canadian dollars, US Midstream adjusted EBIT was US$4 million for the year ended December 31, 2016 compared with US$57 million for the year ended December 31, 2015. The year-over- year decreases in US Midstream adjusted EBIT reﬂected lower volumes primarily attributable to the continued low commodity price environment which resulted in reduced drilling by producers. The decrease in adjusted EBIT was partially offset by lower operating costs. with the Big Foot Pipeline, Heidelberg Pipeline and Stampede US Midstream adjusted EBIT was $73 million for the year ended Pipeline projects. Due to natural production decline, offshore December 31, 2015 compared with $30 million for the year ended pipelines often have available capacity, resulting in signiﬁcant December 31, 2014. The year-over-year increase in adjusted EBIT competition for new developments in the Gulf of Mexico. reﬂected improved operating performance, as well as the favourable Competitive dynamics may impact the ability of the Company effect of translating United States dollar earnings to Canadian dollars to recover its investment in long-lived offshore assets. at higher Average Exchange Rate in 2015 compared with 2014. Natural Disaster Incidents Adjusted EBIT was positively impacted in 2015 by cost reduction efforts undertaken by management resulting in a decrease in contract Adverse weather, such as hurricanes and tropical storms, labour costs and repairs and maintenance costs. Partially offsetting may impact Offshore’s ﬁnancial performance directly or indirectly. these positive impacts were lower volumes primarily as a result Direct impacts may include damage to offshore facilities resulting of reduced drilling programs by producers. 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. As noted above, impacting year-over-year adjusted EBIT is the effect of translating United States dollar earnings to Canadian dollars. The Average Exchange Rate ﬂuctuates period-over-period with a resulting impact on adjusted EBIT. Similar to Lakehead System, a portion of US Midstream United States dollar EBIT is hedged as part of the Company’s enterprise-wide risk mitigation strategy and realized gains and losses from the foreign exchange derivatives instruments are reported within Eliminations and Other. For further details refer to results of Eliminations and Other. 78 Enbridge Inc. 2016 Annual Report Midcoast Energy Partners, L.P. – Drop Down of Interests and Privatization Economic Regulation US Midstream’s economic regulation is driven primarily through EEP holds its natural gas and NGL midstream assets through certain activities within its intrastate natural gas pipelines, which a combination of direct holding and indirect holdings through MEP, are regulated by state regulators. The changing or rejecting a publicly listed partnership trading on the New York Stock of commercial arrangements, including decisions by regulators Exchange. On July 1, 2014, EEP completed the sale of a 12.6% on the applicable tariff structure or changes in interpretations limited partnership interest in its natural gas and NGL midstream of existing regulations by courts or regulators, could have an business to its subsidiary, MEP, for cash proceeds of US$350 million. adverse effect on US Midstream’s revenues and earnings. Delays in Upon ﬁnalization of this transaction, EEP continued to retain a 2% GP regulatory approvals could result in cost escalations and construction interest, an approximate 52% limited partner interest and all IDR delays, which also negatively impact operations. Additionally, while in MEP. However, EEP’s direct interest in entities or partnerships the gas gathering pipelines are not currently subject to FERC rate holding the natural gas and NGL midstream operations reduced regulation, proposals to more actively regulate intrastate gathering from 61% to 48%, with the remaining ownership held by MEP. pipelines are currently being considered in certain of the states The completion of this transaction resulted in a partial monetization in which US Midstream operates. In addition, the FERC has also of EEP’s natural gas and NGL midstream business through sale taken an interest in regulating gas gathering systems that connect to noncontrolling interests (being MEP’s public unitholders). into interstate pipelines. As discussed under United States Sponsored Vehicle Strategy, Competition in May 2016, EEP announced that it was exploring various strategic alternatives for its investments in MEP and Midcoast Operating L.P., the operating subsidiary of MEP. On January 27, 2017, Enbridge announced that it had entered into a merger agreement through a wholly-owned subsidiary, whereby it will take private MEP by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US$170 million in the second quarter of 2017. Business Risks Other interstate and intrastate natural gas pipelines (or their affiliates) and other midstream businesses that gather, treat, process and market natural gas or NGL represent competition to US Midstream. The level of competition varies depending on the location of the gathering, treating and processing facilities. However, most natural gas producers and owners have alternate gathering, treating and processing facilities available to them, including those owned by competitors that are substantially larger than US Midstream. The risks identiﬁed below are speciﬁc to US Midstream. General US Midstream’s marketing segment has numerous competitors, risks that affect the Company as a whole are described under Risk including large natural gas marketing companies, marketing affiliates Management and Financial Instruments – General Business Risks. of pipelines, major oil and natural gas producers, independent Asset Utilization aggregators and regional marketing companies. US Midstream natural gas gathering, processing and transportation Commodity Price Risk assets are subject to market fundamentals affecting natural gas, US Midstream is subject to commodity price risk arising from NGL and related products. Commodity prices impact the willingness movements in natural gas and NGL prices and differentials. of natural gas producers to invest in additional infrastructure These risks have been partially mitigated by using physical to produce natural gas and, with current low natural gas prices, and ﬁnancial contracts to ﬁx the prices of natural gas and NGL. infrastructure plans have been increasingly deferred or cancelled. Certain of these ﬁnancial contracts do not qualify for cash ﬂow These assets are also subject to competitive pressures from hedge accounting; therefore, US Midstream’s EBIT is exposed to third-party and producer-owned gathering systems. associated changes in the mark-to-market value of these contracts. Supply for the marketing operations depends to a large extent Other on the natural gas reserves and rate of drilling within the areas served by the natural gas business. Demand is typically driven by weather- related factors, with respect to power plant and utility customers, and industrial demand. The US Midstream marketing business uses third party storage to balance supply and demand factors. Other is primarily comprised of business development activities for the Company’s gas pipelines businesses and Canadian Midstream and related costs not eligible for capitalization. Management’s Discussion & Analysis 79 Green Power and Transmission Earnings Before Interest and Income Taxes (millions of Canadian dollars) Green Power and Transmission Adjusted earnings before interest and income taxes Green Power and Transmission – changes in unrealized derivative fair value gains/(loss) Green Power and Transmission – investment impairment loss Earnings before interest and income taxes Green Power and Transmission includes approximately 1,900 MW of net operating renewable and alternative energy sources. Of this amount, approximately 930 MW of net power generating capacity comes from wind farms located in the provinces of Alberta, Ontario and Quebec and approximately 780 MW of net power generating capacity comes from wind farms located in the states of Colorado, Texas, Indiana and West Virginia, including the 103-MW New Creek Wind Project which entered service in late December 2016. The vast majority of the power produced from these wind farms is sold under long-term PPAs. The Company also has three solar facilities located in Ontario and a solar facility located in Nevada, with 100 MW and 50 MW, respectively, of net power generating capacity. Also included in Green Power and Transmission is the Montana-Alberta Tie-Line, the Company’s ﬁrst power transmission asset, a transmission line from Great Falls, Montana to Lethbridge, Alberta. Results of Operations 2016 2015 2014 165 165 2 (13) 154 175 175 2 – 177 151 151 (2) – 149 Green Power and Transmission (millions of Canadian dollars) 7 7 1 5 7 1 5 6 1 4 5 1 9 4 1 1 5 1 Adjusted EBIT from Green Power and Transmission was $165 million for the year ended December 31, 2016 compared with adjusted EBIT of $175 million for the year 141 151 161 ended December 31, 2015. Within Green Power and Transmission adjusted EBIT for the year ended December 31, 2016 was US$27 million (2015 – US$27 million) from ■ GAAP EBIT ■■ ■■ ■ Adjusted EBIT its United States’ operations. Excluding the impact of foreign exchange translation to Canadian dollars, adjusted EBIT decreased year-over-year as a result of disruptions at certain eastern Canadian wind farms in the ﬁrst quarter and fourth quarter of 2016 due to weather conditions which caused icing of blades, as well as weaker wind resources experienced at certain facilities in Canada. These negative effects were partially offset by stronger wind resources at the Company’s United States wind farms during the second half of 2016. 1 Effective January 1, 2016, the Company revised its reportable segments and reported Earnings before interest and income taxes for each reporting segment. The above information has reﬂected this change. Adjusted EBIT from Green Power and Transmission was $175 million for the year ended December 31, 2015 compared with adjusted EBIT of $151 million for the year ended December 31, 2014. Within Green Power and Transmission adjusted EBIT for the year ended December 31, 2015 was US$27 million (2014 – US$30 million) from its United States’ operations. Excluding the impact of foreign exchange translation to Canadian dollars, the year-over-year increase in adjusted EBIT reﬂected contributions from new wind farms including Blackspring Ridge which commenced commercial operations in the second quarter of 2014 as well as incremental contributions associated with the purchase of additional interests in the Lac Alfred and Massif du Sud wind projects, which closed in the fourth quarter of 2014. However, the United States operations experienced a slight decrease in adjusted EBIT due to weaker wind resources at Cedar Point wind farm. Adjusted EBIT for the years ended December 31, 2016 and 2015 reﬂected the favourable impact of translating United States dollar earnings at a higher year-over-year Average Exchange Rate in each of 2016 and 2015 on the United States businesses within Green Power and Transmission. 80 Enbridge Inc. 2016 Annual Report Green Power and Transmission CA NA DA Calgary UNITED STA TE S UNITED STA TE S OF AMERICA OF AMERICA Denver Denver Las Vegas Las Vegas Superior Superior Montreal Montreal Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Toronto Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Chicago Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Toledo Cushing Cushing M E X I C 0 Houston Houston Power Transmission in Operation Wind Assets in Operation Solar Assets in Operation Management’s Discussion & Analysis 81 Business Risks The risks identiﬁed below are speciﬁc to the Green Power and Transmission business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments – General Business Risks. Asset Utilization Earnings from Green Power and Transmission assets are highly dependent on weather and atmospheric conditions as well as continued operational availability of these energy producing assets. While the expected energy yields for Green Power and Transmission projects are predicted using long-term historical data, wind and solar resources are subject to natural variation from year to year and from season to season. Any prolonged reduction in wind or solar resources at any of the Green Power and Transmission facilities could lead to decreased earnings and cash ﬂows for the Company. Additionally, inefficiencies or interruptions of Green Power facilities due to operational disturbances or outages resulting from weather conditions or other factors, could also impact earnings. The Company mitigates the risk of operational availability by establishing Operations and Maintenance contracts with the original equipment manufacturers that include a negotiated operational performance asset guarantee. The Company also monitors the operational performance and reliability of the assets on a 24-hour basis. Power produced from Green Power and Transmission assets is also often sold to a single counterparty under PPAs or other long-term pricing arrangements. In this respect, the performance of the Green Power and Transmission assets is dependent on each counterparty performing its contractual obligations under the PPA or pricing arrangement applicable to it. Competition The Company’s Green Power and Transmission assets operate in the North American power markets, which are subject to competition and the supply and demand balance for power in the provinces and states in which they operate. The renewable energy market sector includes large utilities and small independent power producers, which are expected to aggressively compete with the Company for project development opportunities. Energy Services Earnings Before Interest and Income Taxes (millions of Canadian dollars) Energy Services Adjusted earnings before interest and income taxes Energy Services – changes in unrealized derivative fair value gains/(loss) Energy Services – custom duties paid on settlement of dispute Earnings/(loss) before interest and income taxes Following are additional details on Energy Services EBIT: 2016 2015 2014 28 28 (205) (8) (185) 61 61 264 – 325 42 42 688 – 730 • Changes in unrealized fair value gains and losses related to the revaluation of ﬁnancial derivatives used to manage the proﬁtability of transportation and storage transactions and exposure to movements in commodity prices on the value of inventory. • Adjusted EBIT for 2014 excluded a realized loss in 2014 of $193 million incurred to close out certain forward derivative ﬁnancial contracts intended to hedge the value of committed physical transportation capacity in certain markets accessed by Energy Services, but were determined to be no longer effective in doing so. Energy Services provides energy supply and marketing services to North American reﬁners, producers and other customers. Crude oil and NGL marketing services are provided by Tidal Energy. This business transacts at many North American market hubs and provides its customers with various services, including transportation, storage, supply management, hedging programs and product exchanges. Tidal Energy is primarily a physical barrel marketing company focused on capturing value from quality, time and location differentials when opportunities arise. To execute these strategies, Energy Services may lease storage or rail cars, as well as hold nomination or contractual rights on both third party and Enbridge-owned pipelines and storage facilities. Tidal Energy also provides natural gas marketing 82 Enbridge Inc. 2016 Annual Report 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 Adjusted EBIT from Energy Services was $28 million for the year ended December 31, 2016 compared with adjusted EBIT of $61 million for the year ended December 31, 2015. Reported within Energy Services adjusted EBIT for the year ended 2016 was US$32 million (2015 – US$31 million) from its United States operations. Excluding the year-over-year favourable impact of foreign exchange translation to Canadian dollars, the decrease in adjusted EBIT in 2016 reﬂected weaker performance from Energy Services’ Canadian and United States operations during the ﬁrst half of 2016. The compression of certain crude oil location and quality differentials and the impact of a weaker NGL market drove a year-over-year decrease in adjusted EBIT. This decrease was partially offset by the translation of United States dollar earnings to Canadian dollars at a higher Average Exchange Rate in 2016, as well as positive contributions from increased crude oil storage opportunities in the second half of 2016. The positive crude oil storage opportunities were also a driver for the increase in adjusted EBIT in the fourth quarter of 2016 compared with the fourth quarter of 2015. Adjusted EBIT from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods. Energy Services (millions of Canadian dollars) 0 3 7 5 2 3 2 4 1 6 ) 5 8 1 ( 8 2 141 151 161 ■ GAAP EBIT ■■ ■■ ■ Adjusted EBIT 1 Effective January 1, 2016, the Company revised its reportable segments and reported Earnings before interest and income taxes for each reporting segment. The above information has reﬂected this change. Adjusted EBIT from Energy Services was $61 million for the year ended December 31, 2015 compared with adjusted EBIT of $42 million for the year ended December 31, 2014. Reported within Energy Services adjusted EBIT for the year ended December 31, 2015 was US$31 million (2014 – US$60 million loss before interest and income taxes) from its United States’ operations. Excluding the year-over-year favourable impact of foreign exchange translation to Canadian dollars, the increase in adjusted EBIT in 2015 compared with 2014 reﬂected strong reﬁnery demand for certain crude oil feedstock leading to more favourable storage management opportunities. Also contributing to the year-over-year increase in adjusted EBIT were losses realized in the ﬁrst quarter of 2014 on certain ﬁnancial contracts intended to hedge the value of committed transportation capacity, but which were not effective in doing so. During the second and fourth quarters of 2014, the Company closed out a forward component of these derivative contracts which had been determined to be no longer effective. Business Risks The risks identiﬁed below are speciﬁc to Energy Services. General risks that affect the entire Company are described under Risk Management and Financial Instruments – General Business Risks. Commodity Price Risk Energy Services generates margin by capitalizing on quality, time and location differentials when opportunities arise. Volatility in commodity prices and changing marketing conditions could limit margin opportunities. Furthermore, commodity prices could have negative earnings and cash ﬂow impacts if the cost of the commodity is greater than resale prices achieved by the Company. Energy Services activities are conducted in compliance with and under the oversight of the Company’s formal risk management policies, which require the implementation of hedging programs to manage exposure to changes in commodity prices, inclusive of exposures inherent within forecasted transactions. Competition Energy Services earnings are generated from arbitrage opportunities which, by their nature, can be replicated by other competitors. An increase in market participants entering into similar arbitrage transactions could have an impact on the Company’s earnings. The Company’s efforts to mitigate competition risk includes diversiﬁcation of its marketing business by trading at the majority of major hubs in North America and establishing long-term relationships with clients. Management’s Discussion & Analysis 83 Eliminations and Other Earnings Before Interest and Income Taxes (millions of Canadian dollars) Operating and administrative Realized foreign exchange derivative gains/(loss) Other Adjusted loss before interest and income taxes Changes in unrealized derivative fair value gains/(loss) Unrealized intercompany foreign exchange gains/(loss) Employee severance and restructuring costs Project development and transaction costs Drop down transaction costs Asset impairment loss Gain on sale of assets Loss before interest and income taxes Items impacting Eliminations and Other EBIT include: • Employee severance and restructuring costs incurred in 2016 in relation to the Company’s Building Our Energy Future initiative. For additional information, refer to Corporate Vision and Strategy – Strategy – Maintain the Foundation – Attract, Retain and Develop Highly Capable People. • Project development and transaction costs incurred in 2016 in relation to the proposed Merger Transaction. For additional information, refer to Merger Agreement with Spectra Energy. Eliminations and Other includes operating and administrative costs and foreign exchange costs which are not allocated to business segments. Eliminations and Other also includes new business development activities and general corporate investments. Included in Eliminations and Other adjusted loss before interest and income taxes for the year ended December 31, 2016 was a realized loss of $297 million (2015 – $238 million loss; 2014 – $8 million gain) related to settlements under the Company’s foreign exchange risk 2016 2015 2014 (101) (297) 49 (349) 417 (43) (92) (81) – – – (74) (238) 66 (246) (694) 131 (47) – (41) (2) – (80) 8 12 (60) (387) 16 (6) – (35) – 16 (148) (899) (456) Eliminations and Other (millions of Canadian dollars) ) 6 5 4 ( ) 0 6 ( ) 9 9 8 ( ) 6 4 2 ( ) 8 4 1 ( ) 9 4 3 ( management program. The Company targets to hedge 80% or more of anticipated 141 151 161 consolidated United States denominated earnings from its United States operations utilizing foreign exchange derivative contracts with the objective of enhancing the ■ GAAP EBIT ■■ ■■ ■ Adjusted EBIT predictability of its Canadian dollar earnings and ACFFO. The notional amount of foreign currency derivatives realized during 2016 was US$1,044 million (2015 – US$952 million; 2014 – US$910 million) with an average price to sell United States dollars for Canadian dollars at $1.04 (2015 – $1.03; 2014 – $1.11). The Average Exchange Rate for the year ended December 31, 2016 was $1.32 (2015 – $1.28; 2014 – $1.10). 1 Effective January 1, 2016, the Company revised its reportable segments and reported Earnings before interest and income taxes for each reporting segment. The above information has reﬂected this change. As the hedge rate was lower than the Average Exchange Rate in 2016 and 2015, the Company recognized realized hedge losses in each of these periods. The realized hedge loss for the year ended December 31, 2016 was greater than the comparative 2015 period due to higher notional amount of foreign currency derivatives and a greater unfavourable spread between the Average Exchange Rate and hedge rate. The realized loss in Eliminations and Other serves to partially offset the positive effect of translating the earnings performance of United States dollar denominated businesses at the 2016 Average Exchange Rate of $1.32 which is reﬂected in the reported EBIT of the applicable business segments. In 2014, the hedge rate approximated the Average Exchange Rate and therefore the realized gain was not signiﬁcant. 84 Enbridge Inc. 2016 Annual Report Realized gains and losses on this hedging program are reported in their entirety within Eliminations and Other as the Company manages the foreign exchange risk of its United States businesses at an enterprise-wide level. Gains and losses arising on settlements of foreign exchange derivatives hedging transactional exposure from foreign denominated revenues or expenses within the Company’s Canadian businesses are captured at the business level and reported as part of the EBIT of the applicable segment. For example, gains and losses on hedges of the Canadian Mainline’s United States dollar denominated revenue are reported as part of the EBIT from Canadian Mainline. For further details on the Company’s other risk management programs refer to Risk Management and Financial Instruments – Market Risk – Foreign Exchange Risk. Eliminations and Other adjusted EBIT also reﬂected higher operating and administrative costs in 2016 primarily due to higher depreciation expense resulting from additions to intangible assets, computer hardware and leasehold improvements, as well as lower recoveries from other business segments. Other adjusted EBIT decreased from $66 million for the year ended December 31, 2015 to $49 million for the year ended December 31, 2016. The decrease in adjusted EBIT reﬂected realized foreign exchange losses from the translation of certain intercompany transactions. The increase in adjusted EBIT in 2015 when compared with the corresponding 2014 period was the result of realized foreign exchange gains from the translation of certain intercompany transactions. Liquidity and Capital Resources The maintenance of ﬁnancial strength and ﬂexibility is fundamental to Enbridge’s growth strategy, particularly in light of the signiﬁcant level of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside Enbridge’s control, including but not limited to ﬁnancial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, the Company actively manages ﬁnancial plans and strategies to ensure it maintains sufficient liquidity to meet routine operating and future capital requirements. In the near term, the Company generally expects to utilize cash from operations and capital markets issuances, commercial paper and/or credit facility draws to fund liabilities as they become due, ﬁnance capital expenditures, fund debt retirements and pay common and preference share dividends. The Company targets to maintain sufficient liquidity through securement of committed credit facilities with a diversiﬁed group of banks and ﬁnancial institutions to enable it to fund all anticipated requirements for approximately one year without accessing the capital markets. The Company’s ﬁnancing plan is regularly updated to reﬂect evolving capital requirements and ﬁnancial market conditions and identiﬁes a variety of potential sources of debt and equity funding alternatives, including utilization of its sponsored vehicles. For additional information, refer to Sponsored Vehicles below. Capital Market Access The Company and its self-funding subsidiaries ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive. In accordance with its funding plan, the Company completed the following capital market issuances in 2016: Entity (millions of Canadian dollars, unless stated otherwise) Enbridge Enbridge Enbridge Enbridge ENF EGD EPI (via the Fund Group) Type of Issuance Common shares Preference shares United States dollar term notes Fixed-to-ﬂoating subordinated term notes Common shares Medium-term notes Medium-term notes Amount 2,300 750 US$1,500 US$750 575 300 800 Management’s Discussion & Analysis 85 Bank Credit and Liquidity To ensure ongoing liquidity and mitigate the risk of capital market disruption, Enbridge maintains ready access to funds through committed bank credit facilities and it actively manages its bank funding sources to optimize pricing and other terms. The following table provides details of the Company’s committed credit facilities at December 31, 2016 and 2015. December 31, (millions of Canadian dollars) Enbridge Enbridge (U.S.) Inc. EEP EGD The Fund Enbridge Pipelines (Southern Lights) L.L.C. EPI Enbridge Southern Lights LP MEP Total committed credit facilities Maturity Total Facilities Draws1 Available 2016 2017 – 2020 2018 – 2019 2018 – 2020 2018 – 2019 2019 2018 2018 2018 2018 8,183 3,934 3,525 1,017 1,500 27 3,000 5 900 22,091 4,700 126 2,293 360 236 – 1,032 – 564 9,311 3,483 3,808 1,232 657 1,264 27 1,968 5 336 12,780 2015 Total Facilities 6,988 4,470 3,598 1,010 1,500 28 3,000 5 1,121 21,720 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. In 2016, the Company further diversiﬁed its access to funding through the establishment of two term credit facilities with syndicates of Asian banks for a total commitment of $968 million. These facilities were fully drawn upon in the second quarter of 2016 and provided a cost effective source of United States dollar term debt ﬁnancing when compared with the cost of term debt ﬁnancing in the United States public market at the time. In addition to the committed credit facilities noted above, the Company also maintains $335 million (2015 – $349 million) of uncommitted demand facilities, of which $177 million (2015 – $185 million) were unutilized as at December 31, 2016. The Company’s net available liquidity of $14,274 million at December 31, 2016 was inclusive of $2,117 million of unrestricted cash and cash equivalents and net of bank indebtedness of $623 million as reported on the Consolidated Statements of Financial Position. The Company’s credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment may be required if the Company were to default on payment or violate certain covenants. As at December 31, 2016, the Company was in compliance with all debt covenants and expects to continue to comply with such covenants. Strong growth in internal cash ﬂow, ready access to liquidity from diversiﬁed sources and a stable business model have enabled Enbridge to manage its credit proﬁle. The Company actively monitors and manages key ﬁnancial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of ﬁnancial strength that are closely managed include the ability to service debt obligations from operating cash ﬂow and the ratio of debt to total capital. As at December 31, 2016, the Company’s debt capitalization ratio was 62.1% compared with 65.5% as at December 31, 2015. Following the Company’s announcement of the Merger Transaction, the Company’s credit ratings were affirmed as follows: • DBRS Limited (DBRS) conﬁrmed the Company’s issuer rating and medium-term notes and unsecured debentures rating of BBB (high), preference share rating of Pfd-3 (high) and commercial paper rating of R-2 (high), but changed their rating outlook from stable to under review, with developing implications. • Moody’s Investor Services, Inc. affirmed the Company’s issuer rating and medium-term notes and unsecured debt rating of Baa2, preference share rating of Ba1 and commercial paper rating of P-2, and retained a negative outlook. 86 Enbridge Inc. 2016 Annual Report • Standard & Poor’s Rating Services (S&P) affirmed the Company’s corporate credit rating and unsecured debt rating of BBB+, preference share rating of P-2 (low) and commercial paper rating of A-1 (low), and reaffirmed a stable outlook. S&P also affirmed the Company’s global overall short-term rating of A-2. S&P also upgraded Enbridge’s pro forma ﬁnancial risk proﬁle to “signiﬁcant” from “aggressive” due to the improved risk proﬁle and projected credit metrics of the combined Company. Enbridge’s solid investment grade credit rating is a reﬂection of the low risk nature of the underlying assets and limited exposure to commodity prices and volume risk; its project execution track record; strong dividend coverage; and substantial standby liquidity. The Company continues to execute its growth capital program and believes that it continues to have access to capital markets in both Canada and the United States to adequately fund the execution of its growth capital program. The Company invests surplus cash in short-term investment grade money market instruments with highly creditworthy counterparties. Short-term investments were $800 million as at December 31, 2016 compared with $27 million as at December 31, 2015. The higher short-term investment balances at the end of 2016 reﬂect the temporary investment of a portion of capital markets funding undertaken by the Company in the fourth quarter pending its redeployment in growth capital program. At December 31, 2016, all short-term money market investments were rated not less than R-1 (low), A and A2 by DBRS, S&P and Moody’s Investor Services, Inc., respectively. There are no material restrictions on the Company’s cash with the exception of the restricted cash of $68 million, which includes EGD’s receipt of cash from the Government of Ontario to fund its GIF program, cash collateral and for speciﬁc shipper commitments. Cash and cash equivalents held by EEP and the Fund Group are generally not readily accessible by Enbridge until distributions are declared and paid by these entities, which occurs quarterly for EEP and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative uses by Enbridge. Excluding current maturities of long-term debt, at December 31, 2016 and 2015 the Company had a negative working capital position of $456 million and $1,227 million, respectively. In both periods, the major contributing factor to the negative working capital position was the ongoing funding of the Company’s growth capital program. To address this negative working capital position, the Company maintains signiﬁcant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due. As at December 31, 2016, the net available liquidity totalled $14,274 million (2015 – $10,325 million). It is anticipated that any current maturities of long-term debt will be reﬁnanced upon maturity. December 31, (millions of Canadian dollars) Cash and cash equivalents1 Accounts receivable and other2 Inventory Bank indebtedness Short-term borrowings Accounts payable and other3 Interest payable Environmental liabilities Working capital 1 Includes Restricted cash. 2 Includes Accounts receivable from affiliates. 3 Includes Accounts payable to affiliates. 2016 2015 2,185 4,992 1,233 (623) (351) (7,417) (333) (142) (456) 1,049 5,437 1,111 (361) (599) (7,399) (324) (141) (1,227) Management’s Discussion & Analysis 87 Sources and Uses of Cash December 31, (millions of Canadian dollars) Operating activities Investing activities Financing activities Effect of translation of foreign denominated cash and cash equivalents Increase/(decrease) in cash and cash equivalents Signiﬁcant sources and uses of cash for the years ended December 31, 2016 and December 31, 2015 are summarized below: Operating Activities 2016 • • The growth in cash ﬂow delivered by operations in 2016 is a reﬂection of the positive operating factors discussed under Performance Overview – Adjusted EBIT and Performance Overview – Adjusted Earnings, which primarily included stronger contributions from the Liquids Pipelines segment, partially offset by higher ﬁnancing costs resulting from the incurrence of incremental debt to fund asset growth and the impact of reﬁnancing construction debt with longer-term debt ﬁnancing. Changes in operating assets and liabilities included within operating activities were $358 million for the year ended December 31, 2016 compared with $645 million for the comparative 2015 year. Enbridge’s operating assets and liabilities ﬂuctuate in the normal course due to various factors including ﬂuctuations in commodity prices and activity levels within the Energy Services and Gas Distribution segments, the timing of tax payments, general variations in activity levels within the Company’s businesses, as well as timing of cash receipts and payments. 2015 2016 2015 2014 5,211 (5,192) 1,102 (19) 1,102 4,571 (7,933) 2,973 143 (246) 2,547 (11,891) 9,770 59 485 Cash Provided by Operating Activities (millions of Canadian dollars) 1 4 3 3 , 4 7 8 2 , 7 4 5 2 , 1 1 2 5 , 1 7 5 4 , • • The growth in cash ﬂow delivered by operations in 2015 compared with 2014 is also a reﬂection of the positive operating factors discussed under Performance Overview – Adjusted EBIT and Performance Overview – Adjusted Earnings, which primarily include higher throughput on the Canadian Mainline, higher volumes and tolls on the Lakehead System, contributions from new liquids pipeline assets placed into service in recent years and strong reﬁnery demand for crude oil feedstock leading to more favourable storage management opportunities for Energy Services. Partially offsetting these positive factors were higher ﬁnancing costs associated with funding of the Company’s growth program. 12 13 14 15 16 Changes in operating assets and liabilities included within operating activities resulted in a cash outﬂow of $645 million for the year ended December 31, 2015 compared with an outﬂow of $1,699 million for the comparative 2014 period. The favourable variance for changes in operating assets and liabilities was attributable primarily to a negative impact in early 2014 related to signiﬁcantly higher natural gas prices combined with colder weather which lead to increased natural gas demand within the Company’s gas distribution business, resulting in the Company accumulating a signiﬁcant regulatory receivable as at December 31, 2014. A signiﬁcant portion of these regulatory receivables was settled in 2015. Partially offsetting the favourable variance was higher inventory in Energy Services, as a result of increased activity in conjunction with the completion of the Seaway Pipeline Twin and Flanagan South projects in late 2014. 88 Enbridge Inc. 2016 Annual Report Investing Activities The Company continues with the execution of its growth capital program which is further described in Growth Projects – Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements. A summary of additions to property, plant and equipment for the years ended December 31, 2016, 2015 and 2014 is set out below: Year ended December 31, (millions of Canadian dollars) Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other Total capital expenditures 2016 • The timing of projects approval, construction and in-service dates impact the timing of cash requirements. For the year ended December 31, 2016, additions to property, plant and equipment resulted in cash expenditures of $5,128 million compared with $7,273 million for the year ended December 31, 2015. The year-over-year decrease reﬂected the successful completion of growth projects in 2015, including the Edmonton to Hardisty Expansion, Southern Access Extension and phases of the Eastern Access Program. • Also contributing to the decrease in year-over-year cash used in investing activities was proceeds received from disposition of assets. For the year ended December 31, 2016, proceeds from dispositions were $1,379 million compared with $146 million for the year ended December 31, 2015. The majority of the proceeds in 2016 related to the sale of the South Prairie Region assets completed in December 2016. • Partially offsetting the above factors was higher spending by the Company in 2016 for acquisitions. During the second quarter of 2016, the Company made an initial equity investment in and advanced an affiliate loan to acquire a 50% interest in a French offshore wind development company and fund the ongoing development costs of that company. 2015 • For the year ended December 31, 2015, additions to property, plant and equipment resulted in cash spending of $7,273 million compared with $10,524 million for the year ended December 31, 2014. As previously noted, the timing of growth projects’ approval, construction and in-service dates impact the timing of cash requirements. In 2014, higher capital additions reﬂected expenditures on signiﬁcant growth projects brought into service, including Flanagan South, as well as ongoing expenditures on major components of the Eastern Access Program and Edmonton to Hardisty Expansion project, which were completed in 2015. 2016 2015 2014 3,956 5,882 8,911 713 176 251 – 32 858 385 68 – 80 610 593 333 3 74 5,128 7,273 10,524 Capital Expenditures (millions of Canadian dollars) 4 2 5 0 1 , 3 7 2 7 , 8 2 1 , 5 141 151 161 ■■■■■ ■ Liquids Pipelines ■ Liquids Pipelines ■■ ■ Gas Distribution Gas Distribution ■ Gas Pipelines and Processing ■ Gas Pipelines and Processing ■■■■■ ■ Green Power and Transmission ■ Green Power and Transmission ■ Energy Services ■ Energy Services ■ Elimination and Other ■ Elimination and Other 1 Effective January 1, 2016, the Company revised its reportable segments and reported Earnings before interest and income taxes for each reporting segment. The above information has reﬂected this change. Management’s Discussion & Analysis 89 Financing Activities 2016 2015 • The Company’s ﬁnancing requirements decreased for the year ended December 31, 2016 compared with December 31, 2015, • The Company’s ﬁnancing requirements in 2015 were lower compared with the corresponding period and reﬂected lower primarily reﬂecting lower expenditures on growth capital capital requirements as a result of a combination of timing projects and the proceeds of asset sales. The Company’s of capital expenditures and increased cash ﬂow generation from funding requirements are a reﬂection of the timing of various operations. Additionally, during the ﬁrst eight months of 2015, growth projects. • In 2016, the Company’s overall debt decreased by $149 million compared with an overall increase in debt of $3,663 million during the design and negotiation of the Canadian Restructuring Plan, the Company did not access the public capital markets as regularly as it had in previous years. in 2015. The decrease was mainly due to lower debt requirements resulting from the timing of completion of various growth • In 2015, the Company increased its overall debt by $3,663 million compared with $9,000 million in 2014. The higher debt issuance projects and other sources of funds, primarily the proceeds in 2014 reﬂected greater ﬁnancing needs in support of the from the Company’s common share issuance in March 2016, Company’s growth program. Funding of the Company’s growth which were partly utilized to reduce the Company’s credit program was also achieved through the issuance of preference facilities and commercial paper draws. shares. In 2014, the Company issued $1,365 million of preference • The increase in common share dividends paid in 2016 was attributable to the increase in the common share dividend rate effective March 2016 and higher number of common shares outstanding primarily as a result of the common share issuance noted above. • Distributions to redeemable noncontrolling interests in the Fund Group increased during 2016 compared with the corresponding 2015 period mainly due to a higher per share distribution rate and a larger number of public shares outstanding in ENF. Higher distributions to noncontrolling interests in EEP reﬂected an increase to the per unit distribution in the ﬁrst half of 2016 as well as the effects of a strengthening United States dollar versus the Canadian dollar. shares, whereas there were no preference shares issued in 2015. The overall increase in common shares and preference shares outstanding, along with an increase in the common share dividend rate, resulted in a higher amount of dividends paid by the Company in 2015 compared with 2014. • Included within Financing Activities are contributions and distributions to noncontrolling interests. In 2015 the Company did not issue any preference shares or common shares through public offerings directly; however, through its affiliates mainly the Fund Group and EEP, the Company raised $1,285 million of net proceeds in equity capital. These contributions in 2015 were partially offset by distributions of $794 million to noncontrolling interests; whereas, in 2014, the Company made distributions, net of contributions, of $79 million to its noncontrolling interests. 90 Enbridge Inc. 2016 Annual Report Preference Share Issuances Since July 2011, the Company has issued 290 million preference shares for gross proceeds of approximately $7,277 million with the following characteristics. See Outstanding Share Data. (Canadian dollars, unless otherwise stated) Gross Proceeds Initial Yield Dividend1 Per Share Base Redemption Value2 Redemption and Right to Conversion Option Date2,3 Convert Into3,4 Series B5 Series D5 Series F5 Series H5 Series J5 Series L5 Series N5 Series P5 Series R5 Series 15 Series 35 Series 55 Series 75 Series 95 Series 115 Series 135 Series 155 Series 175 $500 million $450 million $500 million $350 million US$200 million US$400 million $450 million $400 million $400 million US$400 million $600 million US$200 million $250 million $275 million $500 million $350 million $275 million $750 million 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 5.15% $1.00 $1.00 $1.00 $1.00 US$1.00 US$1.00 $1.00 $1.00 $1.00 US$1.00 $1.00 US$1.10 $1.10 $1.10 $1.10 $1.10 $1.10 $1.29 $25 $25 $25 $25 US$25 US$25 $25 $25 $25 US$25 $25 US$25 $25 $25 $25 $25 $25 $25 June 1, 2017 March 1, 2018 June 1, 2018 September 1, 2018 June 1, 2017 September 1, 2017 December 1, 2018 March 1, 2019 June 1, 2019 June 1, 2018 September 1, 2019 March 1, 2019 March 1, 2019 December 1, 2019 March 1, 2020 June 1, 2020 September 1, 2020 March 1, 2022 Series C Series E Series G Series I Series K Series M Series O Series Q Series S Series 2 Series 4 Series 6 Series 8 Series 10 Series 12 Series 14 Series 16 Series 18 1 The holder is entitled to receive a ﬁxed, cumulative, quarterly preferential dividend, as declared by the Board. With the exception of Series A Preference Shares, such ﬁxed dividend rate resets every ﬁve years beginning on the initial redemption and conversion option date. The Series 17 Preference Shares contain a feature where the ﬁxed dividend rate, when reset every ﬁve years, will not be less than 5.15%. No other series of Preference Shares has this feature. 2 The Company may at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every ﬁfth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a speciﬁed series on the Conversion Option Date and every ﬁfth anniversary thereafter. 4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly ﬂoating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90 day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18); or US$25 x (number of days in quarter/365) x (three month United States Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6)). 5 For dividends declared, see Liquidity and Capital Resources – Sources and Uses of Cash – Dividend Reinvestment and Share Purchase Plan. Common Share Issuances On March 1, 2016, the Company completed the issuance of 56.5 million common shares for gross proceeds of approximately $2.3 billion, inclusive of the shares issued on exercise of the full amount of the underwriters’ over-allotment option to purchase an additional 7.4 million common shares. The proceeds were used to reduce short-term indebtedness pending reinvestment in capital projects and are expected to be sufficient to fulﬁll equity funding requirements for Enbridge’s current commercially secured growth program through the end of 2017 before consideration of the additional equity raised by ENF in April 2016. On June 24, 2014, the Company completed the issuance of 7.9 million common shares for gross proceeds of approximately $400 million and on July 8, 2014, issued a further 1.2 million common shares pursuant to the underwriters’ over-allotment option for additional gross proceeds of approximately $60 million. The proceeds were used to fund the Company’s growth projects, reduce short-term indebtedness and for other general corporate purposes. Management’s Discussion & Analysis 91 $0.58300 $0.34375 $0.25000 $0.25000 $0.25000 $0.25000 US $0.25000 US $0.25000 $0.25000 $0.25000 $0.25000 US $0.25000 $0.25000 US $0.27500 $0.27500 $0.27500 $0.27500 $0.27500 $0.27500 $0.34570 Dividend Reinvestment and Share Purchase Plan Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends. For the year ended December 31, 2016, dividends declared were $1,945 million (2015 – $1,596 million), of which $1,150 million (2015 – $950 million) were paid in cash and reﬂected in ﬁnancing activities. The remaining $795 million (2015 – $646 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the years ended December 31, 2016 and 2015, 40.9% and 40.5%, respectively, of total dividends declared were reinvested. On January 5, 2017, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on March 1, 2017 to shareholders of record on February 15, 2017. Common Shares Preference Shares, Series A Preference Shares, Series B Preference Shares, Series D Preference Shares, Series F Preference Shares, Series H Preference Shares, Series J Preference Shares, Series L Preference Shares, Series N Preference Shares, Series P Preference Shares, Series R Preference Shares, Series 1 Preference Shares, Series 3 Preference Shares, Series 5 Preference Shares, Series 7 Preference Shares, Series 9 Preference Shares, Series 11 Preference Shares, Series 13 Preference Shares, Series 15 Preference Shares, Series 17 Sponsored Vehicles The Company utilizes its sponsored vehicles to enhance its enterprise-wide funding program. The Company’s drop-down strategy, whereby Enbridge sells mature, stable assets generating reliable cash ﬂows to its sponsored vehicles, involves monetizing assets with the objective of diversifying funding sources and maintaining access to low cost capital. The Fund Group In November 2014, Enbridge ﬁnalized an agreement to transfer natural gas and diluent pipeline interests to the Fund for a total consideration of $1.8 billion. For further details, refer to The Fund Group 2014 Drop Down Transaction. In September 2015, the Company completed the Canadian Restructuring Plan. For further details, refer to Canadian Restructuring Plan. EEP In the United States, the restructuring of EEP’s equity was completed in 2014 as discussed below. Further, in January 2015, Enbridge and EEP completed the drop down of Enbridge’s 66.7% interest in the United States segment of the Alberta Clipper Pipeline to EEP. Aggregate consideration for the transaction was US$1 billion, consisting of approximately US$694 million of Class E equity units issued to Enbridge by EEP and the repayment of approximately US$306 million of indebtedness owed to Enbridge. Refer to Liquids Pipelines – Lakehead System – Alberta Clipper Drop Down. 92 Enbridge Inc. 2016 Annual Report In May 2016, EEP announced that it was exploring various strategic common unit distribution below US$0.5435 per unit in any quarter alternatives for its investments in Midcoast Operating Partners, L.P. during the next ﬁve years, the distribution on the Class D units will be and MEP. On January 27, 2017, Enbridge announced that it had reduced to the amount which would have been received by Enbridge entered into a merger agreement through a wholly-owned subsidiary, under the IDR as if the Equity Restructuring had not occurred. whereby it will take private MEP by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US$170 million in the second quarter of 2017. For additional information on Enbridge’s on-going strategic review of EEP, refer to United States Sponsored Vehicle Strategy. Economic Interest Enbridge’s ownership interest in EEP is impacted by EEP’s issuance and sale of its Class A common units. To the extent Enbridge does not fully participate in these offerings, the Company’s economic interest in EEP is reduced. At December 31, 2016, Enbridge’s economic interest in EEP was 35.3% (2015 – 35.7%, 2014 – 33.7%). The Company’s average economic interest in EEP during 2016 was 35.5% (2015 – 36.0%, 2014 – 27.3%). Additionally, Enbridge also holds a US$1.2 billion investment in EEP preferred units as further described below under EEP Preferred Unit Private Placement. Common Unit Issuance 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. In March 2015, EEP completed the issuance of eight million Class A Distributions common units for gross proceeds of approximately US$294 million before underwriting discounts and commissions and offering expenses. Enbridge did not participate in the issuance; however, the Company made a capital contribution of US$6 million to maintain its 2% GP interest in EEP. EEP used the proceeds from the offering to fund a portion of its capital expansion projects and for general partnership purposes. Equity Restructuring In July 2014, EEP increased its quarterly distribution from US$0.5435 per unit to common unitholders to US$0.5550. On December 23, 2014, EEP announced it would increase its quarterly distribution to US$0.5700 per unit to common unitholders following the announcement that the Alberta Clipper Drop Down was ﬁnalized. Refer to Liquids Pipelines – Lakehead System – Alberta Clipper Drop Down. In July 2015, EEP further increased its quarterly distribution to US$0.5830. In 2016, Enbridge received from EEP, incentive distributions In June 2014, EEP and Enbridge announced an agreement to of US$21 million (2015 – US$19 million, 2014 – US$39 million). restructure EEP’s equity. Effective July 1, 2014, Enbridge Energy Also in 2016, Enbridge received distributions of US$196 million Company, Inc., a wholly-owned subsidiary of Enbridge and the GP from Class D units (2015 – US$195 million, 2014 – US$108 million) of EEP, irrevocably waived its then existing IDR in excess of its and Class E units which were issued under the Equity Restructuring 2% GP interest in exchange for 66.1 million Class D units and 1,000 and Alberta Clipper Drop Down transactions. Incentive Distribution Units (collectively, the Equity Restructuring). The GP share of incremental cash distributions decreased from 48% EEP Preferred Unit Private Placement of all distributions in excess of US$0.4950 per unit per quarter down In 2013, Enbridge invested US$1.2 billion in preferred units of EEP to 23% of all distributions in excess of EEP’s quarterly distribution of to reduce the amount of near-term external funding required by US$0.5435 per unit per quarter. The Class D units carry a distribution EEP to fund its share of the Company’s organic growth program. equal to the quarterly distribution on the Class A common units. The 2014 third and fourth quarter distributions on the Class D units On July 30, 2015, Enbridge and EEP reached an agreement to extend the deferral of quarterly cash distribution on these preferred units. were adjusted to provide Enbridge with an aggregate distribution in The ﬁrst quarterly cash distribution will now occur in the third quarter 2014 equal to the distribution on its IDR as if the Equity Restructuring of 2018 and the deferred distribution will now be payable in equal had not occurred. The Incentive Distribution Units are not entitled to amounts over a 12-quarter period beginning the ﬁrst quarter of 2019. a distribution initially and in the event of any decrease in the Class A Management’s Discussion & Analysis 93 Contractual Obligations Payments due under contractual obligations over the next ﬁve years and thereafter are as follows: (millions of Canadian dollars) Long-term debt1 Capital and operating leases2 Long-term contracts4 Pension obligations3 Total contractual obligations Total 31,967 987 11,055 148 44,157 Less than 1 year 2,599 118 3,714 148 6,579 1 – 3 years 3 – 5 years After 5 years 3,036 145 2,785 – 5,966 4,714 130 2,130 – 6,974 21,618 594 2,426 – 24,638 1 Represents debenture and term note maturities and excludes interest obligations. Changes to the planned funding requirements are dependent on the terms of any debt reﬁnancing agreements. 2 Includes land leases. 3 Assumes only required payments will be made into the pension plans in 2017. Contributions are made in accordance with independent actuarial valuations as at December 31, 2016. Contributions, including discretionary payments, may vary pending future beneﬁt design and asset performance. 4 Includes commitments for transportation service agreements totaling $618 million which assume a light to heavy crude oil ratio of 80:20 on certain pipelines and a power charge of $0.06 per barrel. Capital Expenditure Commitments Included within Long-term contracts in the table above are contracts that the Company has signed for the purchase of services, pipe and other materials totalling $1,903 million which are expected to be paid over the next ﬁve years. Tax Matters Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review. Other Litigation The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the ﬁnal outcome of such actions and proceedings cannot be predicted with certainty, Management believes that the resolution of such actions and proceedings will not have a material impact on the Company’s consolidated ﬁnancial position or results of operations. Outstanding Share Data1 Preference Shares Preference Shares, Series A Preference Shares, Series B Preference Shares, Series D Preference Shares, Series F Preference Shares, Series H Preference Shares, Series J Preference Shares, Series L Preference Shares, Series N Preference Shares, Series P Preference Shares, Series R Preference Shares, Series 1 Preference Shares, Series 3 Preference Shares, Series 5 Preference Shares, Series 7 Preference Shares, Series 9 Preference Shares, Series 11 Preference Shares, Series 13 Preference Shares, Series 15 Preference Shares, Series 17 94 Enbridge Inc. 2016 Annual Report Number Conversion Option Date2,3 Redemption and Right to Convert Into3 5,000,000 20,000,000 18,000,000 20,000,000 14,000,000 8,000,000 16,000,000 18,000,000 16,000,000 16,000,000 16,000,000 24,000,000 8,000,000 10,000,000 11,000,000 20,000,000 14,000,000 11,000,000 30,000,000 – June 1, 2017 March 1, 2018 June 1, 2018 September 1, 2018 June 1, 2017 September 1, 2017 December 1, 2018 March 1, 2019 June 1, 2019 June 1, 2018 September 1, 2019 March 1, 2019 March 1, 2019 December 1, 2019 March 1, 2020 June 1, 2020 September 1, 2020 March 1. 2022 – Series C Series E Series G Series I Series K Series M Series O Series Q Series S Series 2 Series 4 Series 6 Series 8 Series 10 Series 12 Series 14 Series 16 Series 18 Common Shares Common Shares – issued and outstanding (voting equity shares) Stock Options – issued and outstanding (20,738,364 vested) 1 Outstanding share data information is provided as at February 6, 2017. Number 943,186,589 35,751,751 2 All preference shares are non-voting equity shares. Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of Preference Shares, the Company may, at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the redemption option date and on every ﬁfth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into cumulative redeemable Preference Shares of a speciﬁed series on a one-for-one basis on the Conversion Option Date and every ﬁfth anniversary thereafter at an ascribed issue price equal to the base redemption value, as discussed under the terms of the respective Preference Shares. Quarterly Financial Information 2016 Q1 Q2 Q3 Q4 Total (millions of Canadian dollars, except for per share amounts) Revenues Earnings/(loss) attributable to common shareholders Earnings/(loss) per common share Diluted earnings/(loss) per common share Dividends paid per common share EGD – warmer/(colder) than normal weather1 Changes in unrealized derivative fair value (gains)/loss1 2015 (millions of Canadian dollars, except for per share amounts) Revenues Earnings/(loss) attributable to common shareholders Earnings/(loss) per common share Diluted earnings/(loss) per common share Dividends paid per common share EGD – warmer/(colder) than normal weather1 Changes in unrealized derivative fair value (gains)/loss1 1 Included in earnings/(loss) attributable to common shareholders. 8,795 1,213 1.38 1.38 0.530 13 (652) Q1 7,929 (383) (0.46) (0.46) 0.465 (33) 977 7,939 301 0.33 0.33 0.530 (7) 1 Q2 8,631 577 0.68 0.67 0.465 6 (296) 8,488 (103) (0.11) (0.11) 0.530 – 32 Q3 8,320 (609) (0.72) (0.72) 0.465 – 654 9,338 365 0.39 0.39 0.530 7 189 34,560 1,776 1.95 1.93 2.120 13 (430) Q4 Total 8,914 378 0.44 0.44 0.465 16 45 33,794 (37) (0.04) (0.04) 1.86 (11) 1,380 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. Management’s Discussion & Analysis 95 In addition to the impacts of weather in EGD’s franchise area and changes in unrealized gains and losses outlined above, signiﬁcant items impacting the consolidated quarterly earnings are noted below: • Included in the fourth quarter of 2016 was a gain of $520 million (after-tax attributable to Enbridge) on the disposal of South Prairie Region assets within the Liquids Pipelines segment. • Included in the fourth quarter of 2016 was an asset impairment charge of $272 million (after-tax attributable to Enbridge) related to Northern Gateway. For additional information, refer to Other Announced Projects Under Development – Liquids Pipelines – Northern Gateway Project. • Included in the fourth quarter of 2016 were employee severance and restructuring costs incurred in relation to the Company’s Building Our Energy Future initiative, with a net charge of $37 million to earnings. For additional information, refer to Corporate Vision and Strategy – Strategy – Maintain the Foundation – Attract, Retain and Develop Highly Capable People. • Included in the fourth quarter of 2016 and second quarter of 2015 were the tax impacts of asset transfers between entities under common control of Enbridge. The intercompany gains realized by the selling entities have been eliminated from the Company’s consolidated ﬁnancial statements. However, as the transaction involved sale of partnership units, the tax consequences remained in consolidated earnings and resulted in charges of $11 million and $39 million, respectively. • In the third quarter of 2016, impairment charges of $1,000 million ($81 million after-tax attributable to Enbridge), including related project costs of $8 million, were recognized in relation to EEP’s Sandpiper Project as discussed in Growth Projects – Commercially Secured Projects – Liquids Pipelines – Sandpiper Project (EEP). In the fourth quarter of 2016, additional project costs of $4 million (nil after-tax attributable to Enbridge) were recognized. • Included in the second and third quarters of 2016 were after-tax costs attributable to Enbridge of $12 million and $10 million, respectively, incurred in relation to the restart of certain of Enbridge’s pipelines and facilities following the northeastern Alberta wildﬁres. • Included in the second quarter of 2016 were impairment charges of $103 million (after-tax attributable to Enbridge) related to Enbridge’s 75% joint venture interest in Eddystone Rail, attributable to market conditions which impacted volumes at the rail facility. • Included in earnings are after-tax insurance recoveries associated with the Line 37 crude oil release which occurred in June 2013. Insurance recoveries of $3 million were recognized in the ﬁrst quarter of 2016, and $9 million and $13 million were recognized in each of the ﬁrst and fourth quarters of 2015, respectively. Earnings also reﬂected after-tax costs of $6 million in the second quarter of 2015 in connection with the Line 37 crude oil release. • Included in the fourth quarter of 2015 were employee severance costs in relation to the Company’s enterprise-wide reduction of workforce, with a net charge of $25 million to earnings. 96 Enbridge Inc. 2016 Annual Report • Included in the fourth quarter of 2015 was an asset impairment charge of US$63 million ($11 million after-tax attributable to Enbridge) related to EEP’s Berthold rail facility due to the inability to renew committed shipper agreements beyond 2016 or secure sufficient spot volume. • Included in the third quarter of 2015 were impacts from the transfer of assets between entities under common control of Enbridge in connection with the transfer of Enbridge’s Canadian Liquids Pipelines business and certain Canadian renewable energy assets to EIPLP in which the Fund has an indirect interest, resulting in a $247 million loss on the de-designation of interest rate hedges, an $88 million write-off of a regulatory asset in respect of taxes and $16 million of transaction costs. • Included in the third quarter of 2015 was an after-tax gain of $44 million on the disposal of non-core assets within the Liquids Pipelines segment. • Included in the second quarter of 2015 was a goodwill impairment charge of $440 million ($167 million after-tax attributable to Enbridge) related to EEP’s natural gas and NGL businesses due to a prolonged decline in commodity prices which reduced producers’ expected drilling programs and negatively impacted volumes on EEP’s natural gas and NGL systems. Finally, the Company is in the midst of a substantial growth capital program and the timing of construction and completion of growth projects may impact the comparability of quarterly results. The Company’s capital expansion initiatives, including construction commencement and in-service dates, are described under Growth Projects – Commercially Secured Projects. Related Party Transactions Other than the drop down transactions between Enbridge and its sponsored vehicles, including the Canadian Restructuring Plan and the transactions under the United States Sponsored Vehicle strategy, all related party transactions are conducted in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. Vector, a joint venture, contracts the services of Enbridge to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, were $7 million for the year ended December 31, 2016 (2015 – $7 million; 2014 – $7 million). Certain wholly-owned subsidiaries within the Liquids Pipelines, Gas Distribution, Gas Pipelines and Processing and Energy Services segments have committed and uncommitted transportation arrangements with several joint venture affiliates that are accounted for using the equity method. Total amounts charged to the Company for transportation services for the year ended December 31, 2016 were $357 million (2015 – $332 million; 2014 – $256 million). A wholly-owned subsidiary within Liquids Pipelines had a lease arrangement with a joint venture affiliate. During the year ended December 31, 2016, expenses related to the lease arrangement totalled $287 million (2015 – $151 million; 2014 – $21 million) and were recorded to Operating and administrative expense. Certain wholly-owned subsidiaries within Gas Distribution and Energy The Company has implemented a policy whereby, at a minimum, Services segments made natural gas and NGL purchases of $98 million it hedges a level of foreign currency denominated earnings (2015 – $228 million; 2014 – $315 million) from several joint venture exposures over a ﬁve year forecast horizon. A combination affiliates during the year ended December 31, 2016. of qualifying and non-qualifying derivative instruments is used Natural gas sales of $49 million (2015 – $5 million; 2014 – $58 million) were made by certain wholly-owned subsidiaries within the Energy Services segment to several joint venture affiliates during the year ended December 31, 2016. 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. Long-Term Notes Receivable From Affiliates Interest Rate Risk Amounts receivable from affiliates include a series of loans to Vector and other affiliates totalling $130 million and $140 million, respectively (2015 – $149 million and $3 million, respectively), which require quarterly interest payments at annual interest rates ranging from 4% to 12%. These amounts are included in Deferred amounts and other assets. Intercompany Accounts Receivable Sale In 2013, certain of EEP’s subsidiaries entered into a Receivables Purchase Agreement (the Receivables Agreement) with a wholly- owned subsidiary of Enbridge, whereby Enbridge would purchase on a monthly basis certain trade and accrued receivables of such subsidiaries through December 2016. The Receivables Agreement was amended in June 2016 to extend the termination date that provides for purchases to occur on a monthly basis through to December 2019 provided accumulated purchases net of collections do not exceed US$450 million at any one point. The primary objective of the accounts receivable transaction is to further enhance EEP’s available liquidity and its cash available from operations for payment of distributions during the next few years until EEP’s large growth capital commitments are permanently funded, as well as to provide an annual saving in EEP’s cost of funding during this period. Risk Management and Financial Instruments Market Risk The Company’s earnings, cash ﬂows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price (collectively, market risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The Company’s earnings and cash ﬂows are exposed to short term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay ﬁxed-receive ﬂoating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a program to signiﬁcantly mitigate the impact of short-term interest rate volatility on interest expense via execution of ﬂoating to ﬁxed interest rate swaps with an average swap rate of 2.4%. The Company’s earnings and cash ﬂows are also exposed to variability in longer term interest rates ahead of anticipated ﬁxed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to signiﬁcantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances via execution of ﬂoating to ﬁxed interest rate swaps with an average swap rate of 3.7%. The Company also monitors its debt portfolio mix of ﬁxed and variable rate debt instruments to maintain a consolidated portfolio of debt within its Board of Directors approved policy limit of a maximum of 25% ﬂoating rate debt as a percentage of total debt outstanding. The Company primarily uses qualifying derivative instruments to manage interest rate risk. Commodity Price Risk The Company’s earnings and cash ﬂows are exposed to changes in commodity prices as a result of its ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. The Company employs ﬁnancial derivative instruments to ﬁx a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments The following summarizes the types of market risks to which the to manage commodity price risk. Company is exposed and the risk management instruments used to mitigate them. The Company uses a combination of qualifying Equity Price Risk and non-qualifying derivative instruments to manage the risks Equity price risk is the risk of earnings ﬂuctuations due to changes noted below. Foreign Exchange Risk 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 The Company generates certain revenues, incurs expenses, revaluation of the outstanding units every period. The Company and holds a number of investments and subsidiaries that are uses equity derivatives to manage the earnings volatility derived denominated in currencies other than Canadian dollars. As a result, from one form of stock-based compensation, Restricted Stock Units. the Company’s earnings, cash ﬂows and OCI are exposed The Company uses a combination of qualifying and non-qualifying to ﬂuctuations resulting from foreign exchange rate variability. derivative instruments to manage equity price risk. Management’s Discussion & Analysis 97 The Effect of Derivative Instruments on the Consolidated Statements of Earnings and Comprehensive Income The following table presents the effect of cash ﬂow hedges and net investment hedges on the Company’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes. Year ended December 31, (millions of Canadian dollars) Amount of unrealized gains/(loss) recognized in OCI Cash ﬂow hedges Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Net investment hedges Foreign exchange contracts Amount of (gains)/loss reclassiﬁed from accumulated other comprehensive income (AOCI) to earnings (effective portion) Foreign exchange contracts1 Interest rate contracts2 Commodity contracts3 Other contracts4 De-designation of qualifying hedges in connection with the Canadian Restructuring Plan Interest rate contracts2 Amount of (gains)/loss reclassiﬁed from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts2 Commodity contracts3 Amount of gains/(loss) from non-qualifying derivatives included in earnings Foreign exchange contracts1 Interest rate contracts2 Commodity contracts3 Other contracts4 2016 2015 2014 (19) (90) 14 39 22 (34) 2 145 (12) (29) 106 – – 61 – 61 935 73 (508) 9 509 77 (275) 9 (47) (248) (484) 9 128 (46) 28 119 338 338 21 5 26 (2,187) (363) 199 (22) (2,373) 8 (1,086) 50 13 (113) (1,128) 8 101 4 (7) 106 – – 216 (6) 210 (936) 4 1,031 7 106 1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues, Commodity 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. Liquidity Risk Liquidity risk is the risk that the Company will not be able to meet its ﬁnancial obligations, including commitments and guarantees, as they become due. In order to manage this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintains substantial capacity under its committed bank lines of credit, as discussed under Liquidity and Capital Resources, to address any contingencies. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium- term notes. The Company also maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. The Company is in compliance with all the terms and conditions of its committed credit facilities as at December 31, 2016. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities. 98 Enbridge Inc. 2016 Annual Report Credit Risk General Business Risks Entering into derivative ﬁnancial instruments may result in Strategic and Commercial Risks exposure to credit risk. Credit risk arises from the possibility that a counterparty will default on its contractual obligations. In order Economic Regulation, Permits and Approvals to mitigate this risk, the Company enters into risk management Many of the Company’s operations are regulated. The nature and transactions primarily with institutions that possess investment degree of regulation and legislation affecting energy companies grade credit ratings. Credit risk relating to derivative counterparties in Canada and the United States have changed signiﬁcantly in past is mitigated through credit exposure limits and contractual years and there is no assurance that further substantial changes requirements, netting arrangements and ongoing monitoring will not occur. of counterparty credit exposure using external credit rating services and other analytical tools. The Company also faces economic regulation, permits and approvals risk, which broadly deﬁned, is the risk that regulators or other The Company generally has a policy of entering into individual government entities change or reject proposed or existing commercial International Swaps and Derivatives Association, Inc. agreements, arrangements including permits and regulatory approvals for new or other similar derivative agreements, with the majority of its projects, such as the Merger Transaction and the Company’s L3R derivative counterparties. These agreements provide for the Program. The changing or rejecting of commercial arrangements, net settlement of derivative instruments outstanding with speciﬁc including decisions by regulators on the applicable tariff structure counterparties in the event of bankruptcy or other signiﬁcant or changes in interpretations of existing regulations by courts or credit event, and would reduce the Company’s credit risk exposure regulators, could have an adverse effect on the Company’s revenues on derivative asset positions outstanding with the counterparties and earnings. Increasing regulatory scrutiny and resulting delays in these particular circumstances. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual in regulatory permits and approvals with respect to projects could result in cost escalations, construction delays and in-service delays which also negatively impact the Company’s operations. requirements, assessment of credit ratings and netting arrangements. The FERC continues to intensify its oversight of ﬁnancial reporting, Within Gas Distribution, credit risk is mitigated by the utilities’ large risk standards and affiliate rules, and in 2014, the Pipeline and and diversiﬁed customer base and the ability to recover an estimate Hazardous Materials Safety Administration issued new pipeline for doubtful accounts through the ratemaking process. The Company standards and regulations on managing gas pipeline integrity. actively monitors the ﬁnancial strength of large industrial customers The Company continues ongoing dialogue with regulatory and, in select cases, has obtained additional security to minimize agencies and participates in industry groups to ensure it is the risk of default on receivables. Generally, the Company classiﬁes informed of emerging issues in a timely manner. 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 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. ﬂows for forwards and swaps and Black-Scholes-Merton pricing Project Execution 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. 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). Management’s Discussion & Analysis 99 Early stage project risks include right-of-way procurement, special Reputation risk often arises as a consequence of some other risk interest group opposition, Crown consultation and environmental event, such as in connection with operational, regulatory or legal and regulatory permitting. Cost escalations or missed in-service risks. Therefore, reputation risk cannot be managed in isolation dates on future projects may impact future earnings and cash ﬂows from other risks. The Company manages reputation risk by: and may hinder the Company’s ability to secure future projects. Construction delays due to regulatory delays, third-party opposition, contractor or supplier non-performance and weather conditions may impact project development. The Company strives to be an industry leader in project execution and through its Major Projects Group, it seeks to mitigate project execution risk. The Major Projects Group is centralized and has a clearly deﬁned governance structure and process for all major projects, with dedicated resources organized to lead and execute each major project. Capital constraints and cost escalation risks are mitigated through structuring of commercial agreements, typically where shippers retain complete or a share of capital cost excess. Detailed cost • 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 tracking and centralized purchasing is used on all major projects to and Enbridge play in people’s lives in order to promote better facilitate optimum pricing and service terms. Strategic relationships understanding of the Company and its businesses; 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 • 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 Gating Control tool which helps to ensure that schedule, cost, safety and quality objectives are on track and met for each stage of a project’s • pursuing socially responsible operations as a longer-term corporate strategy (implemented through the Company’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 CSR Policy, Climate Policy and Indigenous Peoples Policy). For further discussion on this strategy, refer to Corporate Vision and Strategy – Strategy – Maintain the Foundation – Maintain the Company’s Social License to Operate. a strong focus on integrity and public safety. The Company also The Company’s actions noted above are the key mitigation actions actively involves its legal and regulatory teams to work closely against negative public opinion; however, the public opinion risk with the Major Projects Group to engage in open dialogue with cannot be mitigated solely by the Company’s individual actions. government agencies, regulators, land owners, Indigenous peoples The Company actively works with other stakeholders in the industry and special interest groups to identify and develop appropriate to collaborate and work closely with government and Indigenous responses to their concerns regarding the Company’s projects. Public Opinion Public opinion or reputation risk is the risk of negative impacts on the Company’s business, operations or ﬁnancial condition resulting from changes in the Company’s reputation with Peoples communities to enhance the public opinion of the Company, as well as the industry in which it operates. Unless otherwise speciﬁcally stated, none of the content of the policies or initiatives described above are incorporated by reference herein. Transformation Projects stakeholders, special interest groups, political leadership, Transformation projects risk is the risk that a large change the media or other entities. Public opinion may be inﬂuenced management initiative carried out by the Company will fail to fully by certain media and special interest groups’ negative portrayal deliver anticipated results because of a failure by the Company of the industry in which Enbridge operates as well as their to fully address risks associated with change delivery and opposition to development projects, such as the Bakken Pipeline implementation. This could result in negative ﬁnancial, operational System. Potential impacts of a negative public opinion may and reputational impacts to the Company. Such large scale include loss of business, delays in project execution, legal action, change management initiatives include the Merger Transaction increased regulatory oversight or delays in regulatory approval and Enbridge’s Building Our Energy Future initiative. With respect and higher costs. to the Merger Transaction, Enbridge and Spectra Energy have established a joint integration planning team that is laying the foundation for the efficient integration of the two companies once 100 Enbridge Inc. 2016 Annual Report the Merger Transaction closes and to help ensure that anticipated of an emergency. Enbridge also actively engages ﬁrst responders operating synergies are achieved. For further discussion on the through education programs that endeavour to equip ﬁrst Merger Transaction, refer to Merger Agreement with Spectra Energy. responders with the skills and tools to safely and effectively In 2016, Enbridge also launched the Building Our Energy Future respond to a potential incident. initiative, an enterprise-wide transformation program that is intended to drive out focused improvements across the enterprise to ensure an effective and efficient organization that will better support the execution of key strategies, such as the above noted Enbridge and Spectra Energy integration. To mitigate its transformation projects risk associated with the Building Our Energy Future initiative, Enbridge established the Results Delivery Office to manage the integrated plan and roadmap of initiatives, execute the transformation process, 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. provide coaching and support to impacted teams in the areas of Environmental Incident results delivery, tracking progress and identiﬁcation of new risks and establishment of appropriate mitigation steps to address those risks. Planning and Investment Analysis The Company evaluates expansion projects, acquisitions and divestitures on an ongoing basis. Planning and investment analysis is highly dependent on accurate forecasting assumptions and to the extent that these assumptions do not materialize, ﬁnancial performance may be lower or more volatile than expected. Volatility and unpredictability in the economy, both locally and globally, change in cost estimates, project scoping and risk assessment could result in a loss in proﬁts for the Company. Large scale acquisitions such as the Merger Transaction, may involve signiﬁcant integration risk as discussed above under Transformation Projects and under Merger Agreement with Spectra Energy. An environmental incident could have lasting reputational impacts to Enbridge and could impact its ability to work with various stakeholders. In addition to the cost of remediation activities (to the extent not covered by insurance), environmental incidents may lead to an increased cost of operating and insuring the Company’s assets, thereby negatively impacting earnings. The Company mitigates risk of environmental incidents through its ORM Plan, which broadly aims to position Enbridge as the industry leader for system integrity, environmental and safety programs. Mitigation efforts continue to focus on reducing the likelihood of an environmental incident. Under the umbrella of the ORM Plan the Company has continued its maintenance, excavation and repair program which is supported by operating and capital budgets for pipeline integrity. The Company’s $7.5 billion L3R Program, the largest project in the Company’s history, is a further commitment by the Company to its key strategic priority The planning and investment analysis process involves all levels of safety and operational reliability. Once it is completed, the L3R of management and Board of Directors’ review to ensure alignment Program will provide a major enhancement to Enbridge’s mainline across the Company. A centralized corporate development group system by replacing most segments of the Line 3 pipeline with rigorously evaluates all major investment proposals using consistent the latest high-strength steel and coating. due diligence processes, including a thorough review of the asset quality, systems and projected ﬁnancial performance of the assets being assessed. Environmental and Safety Risks Public, Worker and Contractor Safety Although the Company believes its integrated management system, plans and processes mitigate the risk of environmental incidents, there remains a chance that an environmental incident could occur. The ORM Plan also seeks to mitigate the severity of a potential environmental incident through continued process improvements, regular inspections and monitoring of facilities, as well as Several of the Company’s pipelines and distribution systems enhancements in leak detection processes and alarm analysis and related assets are operated in close proximity to populated procedures. The Company has also invested signiﬁcant resources areas and a major incident could result in injury to members to enhance its emergency response plans, operator training of the public. A public safety incident could result in reputational damage to the Company, material repair costs or increased costs and landowner education programs to address any potential environmental incident. 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. 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 Safety and operational reliability are the most important priorities customary for its industry and includes coverage for environmental at Enbridge. Enbridge’s mitigation efforts to reduce the likelihood incidents excluding costs for ﬁnes and penalties. In the unlikely event and severity of a public safety incident are executed primarily that multiple insurable incidents which in aggregate exceed coverage through its ORM Plan and emergency response preparedness, limits occur within the same insurance period, the total insurance as described below in Environmental Incident. The Company also coverage will be allocated among Enbridge entities on an equitable actively engages stakeholders through public safety awareness basis based on an insurance allocation agreement among Enbridge activities to ensure the public is aware of potential hazards and its subsidiaries and associated entities. and understands the appropriate actions to take in the event Management’s Discussion & Analysis 101 Natural Disaster Incident Risk Enbridge is exposed to the risk of natural disaster incidents across many of its businesses. Natural disaster events include ﬂoods, earthquakes, droughts, wildﬁres, lightning strikes, wind storms, ice storms, hail storms, tornadoes and mudslides. Recent wildﬁres inventory and redundancies for critical equipment. Speciﬁcally for Gas Distribution, the GTA project, which was completed in March 2016, is a key mitigation as the project provides signiﬁcant diversiﬁcation of gas supply to EGD’s distribution network and will further reduce the likelihood of a service interruption incident. in Alberta and their adverse consequences for oil sands operations Business Environment Risks demonstrate the potential nature and extent of natural disaster incident risk for Enbridge. Indigenous Peoples Relations Across various businesses, risk treatment measures include construction techniques to limit exposure to natural disaster risk, emergency preparedness plans, business continuity plans, emergency response exercises and insurance in high consequence locations. The Company has made considerable investments in emergency response equipment, training, and additional resources. Insurance coverage also provides protection from loss or damage to Enbridge assets resulting from most natural disaster events. Canadian judicial decisions have recognized that Indigenous peoples’ rights and treaty rights exist in proximity to the Company’s operations and future project developments. The courts have also conﬁrmed that the Crown has a duty to consult with Indigenous peoples when its decisions or actions may adversely affect Indigenous peoples’ rights and interests or treaty rights. Crown consultation has the potential to delay regulatory approval processes and construction, which may affect project economics. In some cases, respecting Indigenous peoples’ rights may mean regulatory approval is denied or the Information Technology Security or Systems Incident conditions in the approval make a project economically challenging. The Company’s infrastructure, applications and data continue Given this environment and the breadth of relationships across to become more integrated, creating an increased risk that failure the Company’s geographic span, Enbridge has implemented an in one system could lead to a failure of another system. There is also Indigenous Peoples Policy. This policy promotes the achievement increasing industry-wide cyber-attacking activity targeting industrial of participative and mutually beneﬁcial relationships with Indigenous control systems and intellectual property. A successful cyber-attack peoples affected by the Company’s projects and operations. could lead to unavailability, disruption or loss of key functionalities Speciﬁcally, the policy sets out principles governing the Company’s within the Company’s industrial control systems which could impact relationships with Indigenous peoples and makes commitments pipeline operations and potentially result in an environmental to work with Indigenous peoples so they may realize beneﬁts or public safety incident. A successful cyber-attack could also lead from the Company’s projects and operations. Notwithstanding to a large scale data breach resulting in unauthorized disclosure, the Company’s efforts to this end, the issues are complex and 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 impact of Indigenous peoples’ relations on Enbridge’s operations and development initiatives is uncertain. Unless otherwise speciﬁcally stated, none of the content of this policy is incorporated The Company has implemented a comprehensive security by reference herein, or otherwise part of, this MD&A. strategy that includes a security policy and standards framework, Special Interest Groups including Non-Governmental Organizations deﬁned governance and oversight, layered access controls, continuous monitoring, infrastructure and network security, threat detection and incident response through a security operations centre. The Company’s security strategy also includes continuing to improve overall intelligence levels related to cyber threat by partnering with a number of external law enforcement agencies and other organizations within its industry. Service Interruption Incident A service interruption due to a major power disruption or curtailment on commodity supply could have a signiﬁcant impact on the Company’s 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. ability to operate its assets and negatively impact future earnings, The Company works proactively with special interest groups and relationships with stakeholders and the Company’s reputation. non-governmental organizations to identify and develop appropriate Speciﬁcally, for Gas Distribution, any prolonged interruptions would responses to their concerns regarding its projects. The Company ultimately impact gas distribution customers. Service interruptions is investing signiﬁcant resources in these areas. Its CSR program that impact the Company’s crude oil transportation services can also reports on the Company’s responsiveness to environmental negatively impact shippers’ operations and earnings as they are and community issues. Refer to Enbridge’s annual CSR Report, 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 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. 102 Enbridge Inc. 2016 Annual Report Critical Accounting Estimates The Company also tests goodwill for impairment annually or more frequently if events or changes in circumstances indicate that it is The following critical accounting estimates discussed below have more likely than not that the fair value of a reporting unit is less than an impact across the various segments of the Company. its carrying value. For the purposes of impairment testing, reporting Depreciation units are identiﬁed as business operations within an operating segment. The Company has the option to ﬁrst assess qualitative Depreciation of property, plant and equipment, the Company’s factors to determine whether it is necessary to perform the two-step largest asset with a net book value at December 31, 2016 of goodwill impairment test. If the two-step goodwill impairment test $64,284 million (2015 – $64,434 million), or 75% of total assets, is performed, the ﬁrst step involves determining the fair value of the is provided following two primary methods. For distinct assets, Company’s reporting units inclusive of goodwill and comparing those depreciation is generally provided on a straight-line basis over values to the carrying value of each reporting unit. If the carrying the estimated useful lives of the assets commencing when value of a reporting unit, including allocated goodwill, exceeds its fair the asset is placed in service. For largely homogeneous value, goodwill impairment is measured as the excess of the carrying groups of assets with comparable useful lives, the pool method amount of the reporting unit’s allocated goodwill over the implied fair of accounting is followed whereby similar assets are grouped and value of the goodwill based on the fair value of the reporting unit’s depreciated as a pool. When group assets are retired or otherwise assets and liabilities. disposed of, gains and losses are not reﬂected in earnings but are booked as an adjustment to accumulated depreciation. Regulatory Assets and Liabilities 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 Certain of the Company’s businesses are subject to regulation by various authorities, including but not limited to, the NEB, the FERC, the Alberta Energy Regulator, the EUB and the OEB. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non-rate-regulated entities. as the demand for crude oil and natural gas and the integrity Regulatory assets represent amounts that are expected of the Company’s systems. Changes in these assumptions could to be recovered from customers in future periods through rates. result in adjustments to the estimated service lives, which could Regulatory liabilities represent amounts that are expected to be result in material changes to depreciation expense in future refunded to customers in future periods through rates or expected periods in any of the Company’s business segments. For certain to be paid to cover future abandonment costs in relation to the NEB’s rate-regulated operations, depreciation rates are approved by the Land Matters Consultation Initiative (LMCI). Long-term regulatory regulator and the regulator may require periodic studies or technical assets are recorded in Deferred amounts and other assets and updates on useful lives which may change depreciation rates. current regulatory assets are recorded in Accounts receivable and Asset Impairment other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts The Company evaluates the recoverability of its property, plant payable and other. Regulatory assets are assessed for impairment and equipment when events or circumstances such as economic if the Company identiﬁes an event indicative of possible impairment. obsolescence, business climate, legal or regulatory changes, or other The recognition of regulatory assets and liabilities is based on the factors indicate it may not recover the carrying amount of the assets. actions, or expected future actions, of the regulator. To the extent The Company continually monitors its businesses, the market and that the regulator’s actions differ from the Company’s expectations, business environments to identify indicators that could suggest the timing and amount of recovery or settlement of regulatory an asset may not be recoverable. An impairment loss is recognized balances could differ signiﬁcantly from those recorded. In the absence when the carrying amount of the asset exceeds its fair value of rate regulation, the Company would generally not recognize as determined by quoted market prices in active markets or present regulatory assets or liabilities and the earnings impact would value techniques. The determination of the fair value using present be recorded in the period the expenses are incurred or revenues value techniques requires the use of projections and assumptions are earned. A regulatory asset or liability is recognized in respect regarding future cash ﬂows and weighted average cost of capital. of deferred income taxes when it is expected the amounts will Any changes to these projections and assumptions could result be recovered or settled through future regulator-approved rates. in revisions to the evaluation of the recoverability of the property, As at December 31, 2016, the Company’s signiﬁcant regulatory plant and equipment and the recognition of an impairment loss assets totalled $1,865 million (2015 – $1,782 million) and signiﬁcant in the Consolidated Statements of Earnings. regulatory liabilities totalled $844 million (2015 – $869 million). Management’s Discussion & Analysis 103 Postretirement Beneﬁts The Company maintains pension plans, which provide deﬁned beneﬁt and/or deﬁned contribution pension beneﬁts and other postretirement beneﬁts (OPEB) to eligible retirees. Pension costs and obligations for the deﬁned beneﬁt pension plans are determined using actuarial methods and are funded through contributions determined using the projected beneﬁt method, which incorporates management’s best estimates of future salary level, other cost escalations, retirement ages of employees and other actuarial factors including discount rates and mortality. The Company determines discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments the Company anticipates making under each of the respective plans. These assumptions are reviewed annually by the Company’s actuaries. Actual results that differ from assumptions are amortized over future periods and therefore could materially affect the expense recognized and the recorded obligation in future periods. The actual return on plan assets exceeded the expectation by $19 million for the year ended December 31, 2016 (2015 – $62 million shortfall) as disclosed in Note 26, Retirement and Postretirement Beneﬁts, to the 2016 Annual Consolidated Financial Statements. The difference between the actual and expected return on plan assets is amortized over the remaining service period of the active employees. The following sensitivity analysis identiﬁes the impact on the December 31, 2016 Consolidated Financial Statements of a 0.5% change in key pension and OPEB assumptions. (millions of Canadian dollars) Decrease in discount rate Decrease in expected return on assets Decrease in rate of salary increase Contingent Liabilities Pension Beneﬁts OPEB Obligation Expense Obligation Expense 241 – (52) 28 11 (12) 24 – – 2 1 – Provisions for claims ﬁled against the Company are determined on a case-by-case basis. Case estimates are reviewed on a regular basis and are updated as new information is received. The process of evaluating claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the ﬁnal determination of which could have a material impact on the ﬁnancial results of the Company and certain of the Company’s subsidiaries and investments are detailed in Note 31, Commitments and Contingencies, of the 2016 Annual Consolidated Financial Statements. In addition, any unasserted claims that later may become evident could have a material impact on the ﬁnancial results of the Company and certain of the Company’s subsidiaries and investments. Asset Retirement Obligations Asset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash ﬂows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. The Company’s estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of the Company’s assets, there is insufficient data or information to reasonably determine the timing of settlement for estimating the fair value of the ARO. In these cases, the ARO cost is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset. In 2009, the NEB issued a decision related to the LMCI, which required holders of an authorization to operate a pipeline under the NEB Act to ﬁle a proposed process and mechanism to set aside funds to pay for future abandonment costs in respect of the sites in Canada used for the operation of a pipeline. The NEB’s decision stated that while pipeline companies are ultimately responsible for the full costs of abandoning pipelines, abandonment costs are a legitimate cost of providing service and are recoverable from the users of the pipeline upon approval by the NEB. 104 Enbridge Inc. 2016 Annual Report Following the NEB’s ﬁnal approval of the collection mechanism and Amendments to the Consolidation Analysis the set-aside mechanism for LMCI, the Company began collecting and setting aside funds to cover future abandonment costs effective January 1, 2015. The funds collected are held in trust in accordance with the NEB decision. The funds collected from shippers are reported within Transportation and other services revenues and Restricted long-term investments. Concurrently, the Company reﬂects the future abandonment cost as an increase to Operating and administrative expense and Other long-term liabilities. Changes In Accounting Policies Adoption of New Standards Classiﬁcation of Deferred Taxes on the Statements of Financial Position Effective January 1, 2016, the Company elected to early adopt Accounting Standards Update (ASU) 2015-17 and applied the standard on a prospective basis. The amendments require that deferred tax liabilities and assets be classiﬁed as noncurrent in the Consolidated Statements of Financial Position. The adoption of the pronouncement did not have a material impact on the Company’s consolidated ﬁnancial statements. Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations Effective January 1, 2016, the Company adopted ASU 2015-16 on a prospective basis. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identiﬁed during the measurement period in the reporting period in which the adjustment amounts are determined. The adoption of the pronouncement did not have a material impact on the Company’s consolidated ﬁnancial statements. Measurement Date of Deﬁned Beneﬁt Obligation and Plan Assets Effective January 1, 2016, the Company adopted ASU 2015-04 on a prospective basis. The revised criteria simplify the fair value measurement of deﬁned beneﬁt plan assets and obligations. The adoption of the pronouncement did not have a material impact on the Company’s consolidated ﬁnancial statements. Simplifying the Presentation of Debt Issuance Costs Effective January 1, 2016, the Company adopted ASU 2015-03 on a retrospective basis which, as at December 31, 2015, resulted in a decrease in Deferred amounts and other assets of $149 million and a corresponding decrease in Long-term debt of $149 million. The new standard requires debt issuance costs related to a recognized debt liability to be presented in the Consolidated Statements of Financial Position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. ASU 2015-15 was adopted in conjunction with the above standard and did not have a material impact on the Company’s consolidated ﬁnancial statements. ASU 2015-15 clariﬁes the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit. Effective January 1, 2016, the Company adopted ASU 2015-02 on a modiﬁed retrospective basis, which amended and clariﬁed the guidance on variable interest entities (VIEs). There was a signiﬁcant change in the assessment of limited partnerships and other similar legal entities as VIEs, including the removal of the presumption that the general partner should consolidate a limited partnership. As a result, the Company has determined that a majority of the limited partnerships that are currently consolidated or equity accounted for are VIEs. The amended guidance did not impact the Company’s accounting treatment of such entities, however, material disclosures for VIEs have been provided, as necessary. Hybrid Financial Instruments Issued in the Form of a Share Effective January 1, 2016, the Company adopted ASU 2014-16 on a modiﬁed retrospective basis. The revised criteria eliminate the use of different methods in practice in the accounting for hybrid ﬁnancial instruments issued in the form of a share. The new standard clariﬁes the evaluation of the economic characteristics and risks of a host contract in these hybrid ﬁnancial instruments. The adoption of the pronouncement did not have a material impact on the Company’s consolidated ﬁnancial statements. Development Stage Entities Effective January 1, 2016, the Company adopted ASU 2014-10 on a retrospective basis. The new standard amends the consolidation guidance to eliminate the development stage entity relief when applying the VIE model and evaluating the sufficiency of equity at risk. The adoption of the pronouncement did not have a material impact on the Company’s consolidated ﬁnancial statements. Future Accounting Policy Changes Clarifying the Deﬁnition of a Business in an Acquisition ASU 2017-01 was issued in January 2017 with the intent of clarifying the deﬁnition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) of assets or businesses. The Company is currently assessing the impact of the new standard on the consolidated ﬁnancial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2017 and is to be applied on a prospective basis. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows ASU 2016-18 was issued in November 2016 with the intent to add or clarify guidance on the classiﬁcation and presentation of changes in restricted cash and restricted cash equivalents within the cash ﬂow statement. The amendments require that changes in restricted cash and restricted cash equivalents should be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash ﬂows. The Company is currently assessing the impact of the new standard on its consolidated ﬁnancial statements. The accounting update is effective for ﬁscal years beginning after December 15, 2017 and is to be applied on a retrospective basis. Management’s Discussion & Analysis 105 Accounting for Intra-Entity Asset Transfers Recognition of Leases ASU 2016-16 was issued in October 2016 with the intent ASU 2016-02 was issued in February 2016 with the intent of improving the accounting for the income tax consequences to increase transparency and comparability among organizations of intra-entity asset transfers other than inventory. Under the new by recognizing lease assets and lease liabilities on the Consolidated guidance, an entity should recognize the income tax consequences Statements of Financial Position and disclosing additional key of an intra-entity transfer of an asset, other than inventory, when information about leasing arrangements. The Company is currently the transfer occurs. The accounting update is effective for annual assessing the impact of the new standard on its consolidated and interim periods beginning on or after December 15, 2017 and ﬁnancial statements. The accounting update is effective for ﬁscal is to be applied on a modiﬁed retrospective basis, with early adoption years beginning after December 15, 2018, and is to be applied using permitted. Effective January 1, 2017, the Company elected to early a modiﬁed retrospective approach. adopt ASU 2016-16. The adoption of the pronouncement is not anticipated to have a material impact on the Company‘s consolidated ﬁnancial statements. Simplifying Cash Flow Classiﬁcation 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, ASU 2016-15 was issued in August 2016 with the intent of reducing presentation, and disclosure of ﬁnancial assets and liabilities. diversity in practice of how certain cash receipts and cash payments The amendments revise accounting related to the classiﬁcation are classiﬁed in the Consolidated Statements of Cash Flows. The new guidance addresses eight speciﬁc presentation issues. The Company is currently assessing the impact of the new standard on its consolidated ﬁnancial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2017 and is to be applied on a retrospective basis. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing ﬁnancial statement users with more useful information about the expected credit losses on ﬁnancial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The amendment adds a new impairment model, known as the current expected credit loss model that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The Company is currently assessing the impact of the new standard on its consolidated ﬁnancial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019. and measurement of investments in equity securities, the presentation of certain fair value changes for ﬁnancial liabilities measured at fair value, and the disclosure requirements associated with the fair value of ﬁnancial instruments. The Company is currently assessing the impact of the new standard on its consolidated ﬁnancial statements. The accounting update is effective for ﬁscal years beginning after December 15, 2017, and is to be applied by means of a cumulative-effect adjustment to the Statements of Financial Position as of the beginning of the ﬁscal year of adoption, with amendments related to equity securities without readily determinable fair values to be applied prospectively. Revenue from Contracts with Customers ASU 2014-09 was issued in 2014 with the intent of signiﬁcantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based ﬁve-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective January 1, 2018. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modiﬁed retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to Improvements to Employee Share-Based Payment Accounting opening retained earnings in the period of adoption. The Company ASU 2016-09 was issued in March 2016 with the intent of simplifying is currently assessing which transition method to use. and improving several aspects of accounting for share-based The Company has reviewed a sample of its revenue contracts payment transactions including the income tax consequences, in order to evaluate the effect of the new standard on its revenue classiﬁcation of awards as either equity or liabilities, and classiﬁcation recognition practices. Based on the Company’s initial assessment, on the Consolidated Statements of Cash Flows. The accounting the application of the standard may result in a change in presentation update is effective for annual and interim periods beginning in the Gas Distribution business related to payments to customers on or after December 15, 2016 and is to be applied on a prospective under the earnings sharing mechanism which are currently shown or retrospective basis. The adoption of the pronouncement as an expense in the Consolidated Statements of Earnings. is not anticipated to have a material impact on the Company’s Under the new standard, these payments would be reﬂected consolidated ﬁnancial statements. as a reduction of revenue. Additionally, estimates of variable 106 Enbridge Inc. 2016 Annual Report consideration which will be required under the new standard for The Company’s internal control over ﬁnancial reporting includes certain Liquids Pipelines, Gas Pipelines and Processing and Green policies and procedures that: Power and Transmission revenue contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts. While the Company has not yet • pertain to the maintenance of records that, in reasonable detail, accurately and fairly reﬂect transactions and dispositions of assets of the Company; completed the assessment, the Company‘s preliminary view is that it does not expect these changes will have a material impact on • provide reasonable assurance that transactions are recorded as necessary to permit preparation of ﬁnancial statements revenue or earnings (loss). The Company is also developing processes in accordance with U.S. GAAP; and • provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the ﬁnancial statements. The Company’s internal control over ﬁnancial reporting may not prevent or detect all misstatements because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the Company’s policies and procedures. Management assessed the effectiveness of the Company’s internal control over ﬁnancial reporting as at December 31, 2016, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management concluded that the Company maintained effective internal control over ﬁnancial reporting as at December 31, 2016. During the year ended December 31, 2016, there has been no material change in the Company’s internal control over ﬁnancial reporting. The effectiveness of the Company’s internal control over ﬁnancial reporting as at December 31, 2016 has been audited by PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company. to generate the disclosures required under the new standard. Controls and Procedures Disclosure Controls and Procedures Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports ﬁled with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods speciﬁed under Canadian and United States securities law. As at December 31, 2016, an evaluation was carried out under the supervision of and with the participation of Enbridge’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of Enbridge’s disclosure controls and procedures (as deﬁned in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by Enbridge in reports that it ﬁles with or submits to the Securities and Exchange Commission (SEC) and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required. Management’s Report on Internal Control Over Financial Reporting Management of Enbridge is responsible for establishing and maintaining adequate internal control over ﬁnancial reporting as such term is deﬁned in the rules of the SEC and the Canadian Securities Administrators. The Company’s internal control over ﬁnancial reporting is a process designed under the supervision and with the participation of executive and ﬁnancial officers to provide reasonable assurance regarding the reliability of ﬁnancial reporting and the preparation of the Company’s ﬁnancial statements for external reporting purposes in accordance with U.S. GAAP. Management’s Discussion & Analysis 107 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 generally accepted accounting principles 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, 2016, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that the Company maintained effective internal control over ﬁnancial reporting as at December 31, 2016. 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 President & Chief Executive Officer February 17, 2017 John K. Whelen Executive Vice President & Chief Financial Officer 108 Enbridge Inc. 2016 Annual Report Independent Auditor’s Report To the Shareholders of Enbridge Inc. We have completed integrated audits of Enbridge Inc.’s 2016, 2015 and 2014 consolidated ﬁnancial statements and its internal control over ﬁnancial reporting as at December 31, 2016. 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, 2016 and December 31, 2015 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, 2016, 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 accepted 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 2016 and December 31, 2015 and the results of its operations and its cash ﬂows for each of the three years in the period ended December 31, 2016 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, 2016, 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 109 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, 2016, based on criteria established in Internal Control – Integrated Framework (2013) issued by COSO. Chartered Professional Accountants Calgary, Alberta February 17, 2017 110 Enbridge Inc. 2016 Annual Report Consolidated Statements of Earnings Year ended December 31, (millions of Canadian dollars, except per share amounts) Revenues Commodity sales Gas distribution sales Transportation and other services Expenses Commodity costs Gas distribution costs Operating and administrative Depreciation and amortization Environmental costs, net of recoveries Impairment of property, plant and equipment (Note 9) Goodwill impairment (Note 15) Income from equity investments (Note 11) Other income/(expense) (Note 27) Interest expense (Note 17) Income taxes (Note 25) Earnings/(loss) from continuing operations Discontinued Operations Earnings from discontinued operations before income taxes Income taxes from discontinued operations Earnings from discontinued operations Earnings/(loss) (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests Earnings attributable to Enbridge Inc. Preference share dividends Earnings/(loss) attributable to Enbridge Inc. common shareholders Earnings/(loss) attributable to Enbridge Inc. common shareholders Earnings/(loss) from continuing operations Earnings from discontinued operations, net of tax Earnings/(loss) per common share attributable to Enbridge Inc. common shareholders Continuing operations Discontinued operations Diluted earnings/(loss) per common share attributable to Enbridge Inc. common shareholders Continuing operations Discontinued operations The accompanying notes are an integral part of these consolidated ﬁnancial statements. 2016 2015 2014 22,816 2,486 9,258 34,560 22,409 1,596 4,360 2,240 (2) 1,376 – 31,979 2,581 428 1,032 (1,590) 2,451 (142) 2,309 – – – 2,309 (240) 2,069 (293) 1,776 1,776 – 1,776 1.95 – 1.95 1.93 – 1.93 23,842 3,096 6,856 33,794 28,281 2,853 6,507 37,641 22,949 27,504 2,292 4,152 2,024 (21) 96 440 31,932 1,862 475 (702) (1,624) 11 (170) (159) – – – (159) 410 251 (288) (37) (37) – (37) (0.04) – (0.04) (0.04) – (0.04) 1,979 3,281 1,577 100 – – 34,441 3,200 368 (266) (1,129) 2,173 (611) 1,562 73 (27) 46 1,608 (203) 1,405 (251) 1,154 1,108 46 1,154 1.34 0.05 1.39 1.32 0.05 1.37 Consolidated Financial Statements 111 Consolidated Statements of Comprehensive Income Year ended December 31, (millions of Canadian dollars) Earnings/(loss) Other comprehensive income/(loss), net of tax Change in unrealized gains/(loss) on cash ﬂow hedges Change in unrealized gains/(loss) on net investment hedges Other comprehensive income from equity investees Reclassiﬁcation to earnings of realized cash ﬂow hedges Reclassiﬁcation to earnings of unrealized cash ﬂow hedges Reclassiﬁcation to earnings of pension plans and other postretirement beneﬁts (OPEB) amortization amounts Actuarial gains/(loss) on pension plans and other postretirement beneﬁts Change in foreign currency translation adjustment Reclassiﬁcation to earnings of derecognized cash ﬂow hedges Other comprehensive income/(loss), net of tax Comprehensive income Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests Comprehensive income attributable to Enbridge Inc. Preference share dividends Comprehensive income attributable to Enbridge Inc. common shareholders The accompanying notes are an integral part of these consolidated ﬁnancial statements. 2016 2015 2014 2,309 (159) 1,608 (138) 166 – 98 18 17 (34) (712) – (585) 1,724 (229) 1,495 (293) 1,202 198 (903) 30 (191) (121) 21 51 3,347 (247) 2,185 2,026 292 2,318 (288) 2,030 (833) (270) 10 76 158 15 (191) 1,238 – 203 1,811 (242) 1,569 (251) 1,318 112 Enbridge Inc. 2016 Annual Report Consolidated Statements of Changes in Equity Year ended December 31, (millions of Canadian dollars, except per share amounts) Preference shares (Note 21) Balance at beginning of year Preference shares issued Balance at end of year Common shares (Note 21) Balance at beginning of year Common shares issued Dividend reinvestment and share purchase plan Shares issued on exercise of stock options Balance at end of year Additional paid-in capital Balance at beginning of year Stock-based compensation Options exercised Issuance of treasury stock Drop down of interest to Enbridge Energy Partners, L.P. (Note 20) Enbridge Energy Partners, L.P. equity restructuring (Note 20) Transfer of interest to Enbridge Income Fund Drop down of interest to Midcoast Energy Partners, L.P. Dilution gain on Enbridge Income Fund issuance of trust units (Note 20) Dilution gain on Enbridge Income Fund equity investment (Note 20) Dilution gain/(loss) on Enbridge Income Fund indirect equity investment (Note 20) Dilution gains and other Balance at end of year Retained earnings/(deﬁcit) Balance at beginning of year Earnings attributable to Enbridge Inc. Preference share dividends Common share dividends declared Dividends paid to reciprocal shareholder Reversal of cumulative redemption value adjustment attributable to Enbridge Commercial Trust (Note 20) Redemption value adjustment attributable to redeemable noncontrolling interests (Note 20) Adjustment relating to equity method investment Balance at end of year Accumulated other comprehensive income/(loss) (Note 23) Balance at beginning of year Other comprehensive income/(loss) attributable to Enbridge Inc. common shareholders Balance at end of year Reciprocal shareholding Balance at beginning of year Issuance of treasury stock Balance at end of year Total Enbridge Inc. shareholders’ equity Noncontrolling interests Balance at beginning of year Earnings/(loss) attributable to noncontrolling interests Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax Change in unrealized gains/(loss) on cash ﬂow hedges Change in foreign currency translation adjustment Reclassiﬁcation to earnings of realized cash ﬂow hedges Reclassiﬁcation to earnings of unrealized cash ﬂow hedges Comprehensive income/(loss) attributable to noncontrolling interests Distributions Contributions Drop down of interest to Enbridge Energy Partners, L.P. (Note 20) Enbridge Energy Partners, L.P. equity restructuring Drop down of interest to Midcoast Energy Partners, L.P. Dilution loss Acquisitions – Magic Valley and Wildcat wind farms (Note 6) Other Balance at end of year Total equity Dividends paid per common share The accompanying notes are an integral part of these consolidated ﬁnancial statements. 2016 2015 2014 6,515 740 7,255 7,391 2,241 795 65 10,492 3,301 41 (24) – – – – – 4 73 4 – 3,399 142 2,069 (293) (1,945) 26 – (686) (29) (716) 1,632 (574) 1,058 (83) (19) (102) 21,386 1,300 (28) 4 (44) 33 7 – (28) (720) 28 – – – – – (3) 577 21,963 2.12 6,515 – 6,515 6,669 – 646 76 7,391 2,549 35 (19) – 218 – – – 355 132 (5) 36 3,301 1,571 251 (288) (1,596) 22 541 (359) – 142 (435) 2,067 1,632 (83) – (83) 18,898 2,015 (407) 161 273 (236) (83) 115 (292) (680) 615 (304) – – (53) – (1) 1,300 20,198 1.86 5,141 1,374 6,515 5,744 446 428 51 6,669 746 31 (14) 22 – 1,601 176 (18) – – – 5 2,549 2,550 1,405 (251) (1,177) 17 – (973) – 1,571 (599) 164 (435) (86) 3 (83) 16,786 4,014 214 (192) 146 18 77 49 263 (535) 212 – (2,330) 39 – 351 1 2,015 18,801 1.40 Consolidated Financial Statements 113 Consolidated Statements of Cash Flows Year ended December 31, (millions of Canadian dollars) Operating activities Earnings/(loss) Earnings from discontinued operations Depreciation and amortization Deferred income taxes (Note 25) Changes in unrealized (gains)/loss on derivative instruments, net Cash distributions in excess of equity earnings Impairment Gains on dispositions (Note 27) Hedge ineffectiveness Inventory revaluation allowance Unrealized (gains)/loss on intercompany loan Other Changes in environmental liabilities, net of recoveries Changes in operating assets and liabilities (Note 29) Cash provided by continuing operations Cash provided by discontinued operations Investing activities Additions to property, plant and equipment Joint venture ﬁnancing Long-term investments Restricted long-term investments Additions to intangible assets Acquisitions Proceeds from dispositions Affiliate loans, net Changes in restricted cash Cash used in continuing operations Cash provided by discontinued operations Financing activities Net change in bank indebtedness and short-term borrowings Net change in commercial paper and credit facility draws Southern Lights project ﬁnancing repayments Debenture and term note issues – Southern Lights Debenture and term note issues Debenture and term note repayments Contributions from noncontrolling interests Distributions to noncontrolling interests Contributions from redeemable noncontrolling interests Distributions to redeemable noncontrolling interests Preference shares issued Common shares issued Preference share dividends Common share dividends Effect of translation of foreign denominated cash and cash equivalents Increase/(decrease) in cash and cash equivalents Cash and cash equivalents at beginning of year – continuing operations Cash and cash equivalents at beginning of year – discontinued operations Cash and cash equivalents at end of year Cash and cash equivalents – discontinued operations Cash and cash equivalents – continuing operations Supplementary cash ﬂow information Income taxes paid Interest paid The accompanying notes are an integral part of these consolidated ﬁnancial statements. 114 Enbridge Inc. 2016 Annual Report 2016 2015 2014 2,309 – 2,240 43 (509) 171 1,620 (848) 61 245 43 198 (4) (358) 5,211 – 5,211 (5,128) (1) (467) (46) (127) (644) 1,379 (118) (40) (5,192) – (5,192) 14 (2,297) – – 4,080 (1,946) 28 (720) 591 (202) 737 2,260 (293) (1,150) 1,102 (19) 1,102 1,015 – 2,117 – 2,117 194 1,820 (159) – 2,024 7 2,373 244 536 (94) (20) 410 (131) 69 (43) (645) 4,571 – 4,571 (7,273) – (622) (49) (101) (106) 146 59 13 (7,933) – (7,933) (588) 1,507 – – 3,767 (1,023) 615 (680) 670 (114) – 57 (288) (950) 2,973 143 (246) 1,261 – 1,015 – 1,015 80 1,835 1,608 (46) 1,577 587 (96) 196 18 (38) 210 174 (16) 131 (78) (1,699) 2,528 19 2,547 (10,524) – (854) – (208) (394) 85 13 (13) (11,895) 4 (11,891) 734 4,212 (1,519) 1,507 5,414 (1,348) 212 (535) 323 (79) 1,365 478 (245) (749) 9,770 59 485 756 20 1,261 – 1,261 9 1,435 Consolidated Statements of Financial Position December 31, (millions of Canadian dollars; number of shares in millions) Assets Current assets Cash and cash equivalents Restricted cash Accounts receivable and other (Note 7) Accounts receivable from affiliates Inventory (Note 8) Property, plant and equipment, net (Note 9) Long-term investments (Note 11) Restricted long-term investments (Note 12) Deferred amounts and other assets (Note 13) Intangible assets, net (Note 14) Goodwill (Note 15) Deferred income taxes (Note 25) Assets held for sale (Note 6) Liabilities and equity Current liabilities Bank indebtedness Short-term borrowings (Note 17) Accounts payable and other (Note 16) Accounts payable to affiliates Interest payable Environmental liabilities Current maturities of long-term debt (Note 17) Long-term debt (Note 17) Other long-term liabilities (Note 18) Deferred income taxes (Note 25) Commitments and contingencies (Note 31) Redeemable noncontrolling interests (Note 20) Equity Share capital (Note 21) Preference shares Common shares (943 and 868 outstanding at December 31, 2016 and December 31, 2015, respectively) Additional paid-in capital Retained earnings/(deﬁcit) Accumulated other comprehensive income (Note 23) Reciprocal shareholding Total Enbridge Inc. shareholders’ equity Noncontrolling interests (Note 20) Variable Interest Entities (Note 10) The accompanying notes are an integral part of these consolidated ﬁnancial statements. Approved by the Board of Directors: 2016 2015 2,117 68 4,978 14 1,233 8,410 64,284 6,836 90 3,113 1,573 78 1,170 278 1,015 34 5,430 7 1,111 7,597 64,434 7,008 49 3,160 1,348 80 839 – 85,832 84,515 623 351 7,295 122 333 142 4,100 12,966 36,494 4,981 6,036 60,477 361 599 7,351 48 324 141 1,990 10,814 39,391 6,056 5,915 62,176 3,392 2,141 7,255 10,492 3,399 (716) 1,058 (102) 21,386 577 21,963 85,832 6,515 7,391 3,301 142 1,632 (83) 18,898 1,300 20,198 84,515 David A. Arledge Chair J. Herb England Director Consolidated Financial Statements 115 Notes to the Consolidated Financial Statements 1. General Business Description Energy Services 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 and Processing; Green Power and The Energy Services businesses in Canada and the United States undertake physical commodity marketing activity and logistical services, oversee reﬁnery supply services and manage the Company’s volume commitments on various pipeline systems. Transmission; and Energy Services. These reporting segments are Eliminations and Other 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. Liquids Pipelines Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and reﬁned products pipelines and terminals in Canada and the United States, including Canadian Mainline, In addition to the segments noted above, Eliminations and Other includes operating and administrative costs and foreign exchange costs which are not allocated to business segments. Also included in Eliminations and Other are new business development activities, general corporate investments and elimination of transactions between segments required to present ﬁnancial performance and ﬁnancial position on a consolidated basis. Lakehead Pipeline System (Lakehead System), Regional Oil Sands Canadian Restructuring Plan System, Mid-Continent and Gulf Coast, Southern Lights Pipeline, Bakken System and Feeder Pipelines and Other. Gas Distribution Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD), which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution 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 activities in Quebec and New Brunswick and the Company’s Plan). The consideration that Enbridge received included $18.7 billion investment in Noverco Inc. (Noverco). Gas Pipelines and Processing 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 Gas Pipelines and Processing consists of investments in natural of approximately $11.7 billion. gas pipelines and gathering and processing facilities. Investments in natural gas pipelines include the Company’s interests in Alliance Pipeline, Vector Pipeline (Vector) and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing 2. Summary of Signiﬁcant Accounting Policies include the Company’s interest in Aux Sable, a natural gas extraction These consolidated ﬁnancial statements are prepared in accordance and fractionation business located near the terminus of the Alliance with generally accepted accounting principles in the United States Pipeline, Canadian Midstream assets located in northeast British Columbia and northwest Alberta and United States Midstream assets located primarily in Texas and Oklahoma. Green Power and Transmission Green Power and Transmission consists of the Company’s investments in renewable energy assets and transmission facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United States primarily in Colorado, Texas, Indiana and West Virginia. The Company also has assets under development located in Europe. 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); 116 Enbridge Inc. 2016 Annual Report allowance for doubtful accounts (Note 7); depreciation rates and As a result of the Canadian Restructuring Plan, ECT, a subsidiary carrying value of property, plant and equipment (Note 9); amortization of the Company, determines its equity investment earnings from rates of intangible assets (Note 14); measurement of goodwill (Note 15); EIPLP using the Hypothetical Liquidation at Book Value (HLBV) fair value of asset retirement obligations (ARO) (Note 19); valuation method. ECT applies the HLBV method to its equity method of stock-based compensation (Note 22); fair value of ﬁnancial investments where cash distributions, including both preference instruments (Note 24); provisions for income taxes (Note 25); assumptions and residual distributions, are not based on the investor’s ownership used to measure retirement and other postretirement beneﬁt percentages. Under the HLBV method, a calculation is prepared obligations (OPEB) (Note 26); commitments and contingencies (Note 31); at each balance sheet date to determine the amount that ECT and estimates of losses related to environmental remediation would receive if EIPLP were to liquidate all of its assets, as valued in obligations (Note 31). Actual results could differ from these estimates. accordance with U.S. GAAP, and distribute that cash to the investors. Principles of Consolidation The consolidated ﬁnancial statements include the accounts 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 Enbridge, its subsidiaries and variable interest entities (VIEs) for of the earnings or losses from the equity investment for the period. which the Company is the primary beneﬁciary. A VIE is a legal entity that does not have sufficient equity at risk to ﬁnance its activities without additional subordinated ﬁnancial support or is structured such that equity investors lack the ability to make signiﬁcant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. 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 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. entity is a VIE. The primary beneﬁciary has both the power to direct Regulation 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 entity that could potentially be signiﬁcant to the VIE. Where the Company concludes it is the primary beneﬁciary of a VIE, the Company will consolidate the accounts of that entity. The Company assesses all variable interests 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 reconsideration of whether an entity is a VIE occurs when there are certain changes in the facts and circumstances related to a VIE. The Company assesses the primary beneﬁciary determination for a VIE on an ongoing basis, as there are changes in the facts and circumstances related to a VIE. 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. 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 All signiﬁcant intercompany accounts and transactions are for impairment if the Company identiﬁes an event indicative eliminated upon consolidation. Ownership interests in subsidiaries of possible impairment. The recognition of regulatory assets represented by other parties that do not control the entity are and liabilities is based on the actions, or expected future actions, presented in the consolidated ﬁnancial statements as activities of the regulator. To the extent that the regulator’s actions differ and balances attributable to noncontrolling interests and redeemable from the Company’s expectations, the timing and amount of recovery noncontrolling interests. Investments and entities over which the or settlement of regulatory balances could differ signiﬁcantly from Company exercises signiﬁcant inﬂuence are accounted for using those recorded. In the absence of rate regulation, the Company the equity method. would generally not recognize regulatory assets or liabilities and Notes to the Consolidated Financial Statements 117 the earnings impact would be recorded in the period the expenses Certain offshore pipeline transportation contracts require the Company are incurred or revenues are earned. A regulatory asset or liability is to provide transportation services for the life of the underlying recognized in respect of deferred income taxes when it is expected producing ﬁelds. Under these arrangements, shippers pay the the amounts will be recovered or settled through future regulator- Company a ﬁxed monthly toll for a deﬁned period of time which may approved rates. 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, 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. a cost of equity component, which are both capitalized based on rates For rate-regulated businesses, revenues are recognized in a manner set out in a regulatory agreement. In the absence of rate regulation, that is consistent with the underlying agreements as approved the Company would capitalize interest using a capitalization rate by the regulators. Since July 1, 2011 onward, Canadian Mainline based on its cost of borrowing, whereas the capitalized equity (excluding Lines 8 and 9) earnings are governed by the Competitive component, the corresponding earnings during the construction Toll Settlement (CTS), under which revenues are recorded when phase and the subsequent depreciation would not be recognized. services are performed. Effective on that date, the Company 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 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. calculated in accordance with U.S. GAAP in early years of long-term For natural gas utility rate-regulated operations in Gas Distribution, contracts but recovered in future periods when tolls exceed revenues are recognized in a manner consistent with the underlying depreciation. Depreciation expense on such assets is recorded rate-setting mechanism as mandated by the regulator. Natural gas in accordance with U.S. GAAP and no deferred regulatory asset utilities revenues are recorded on the basis of regular meter readings 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 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. the Company’s expectations, the timing and amount of recovery For natural gas and marketing businesses, an estimate of revenues or settlement of capitalized costs could differ signiﬁcantly from and commodity costs for the month of December is included those recorded. In the absence of rate regulation, a portion in the Consolidated Statements of Earnings for each year based of such costs may be charged to current period earnings. on the best available volume and price data for the commodity Revenue Recognition For businesses that are not rate-regulated, revenues are recorded delivered and received. Derivative Instruments and Hedging when products have been delivered or services have been performed, Non-qualifying Derivatives 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. 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, Long-term take-or-pay contracts, under which shippers are obligated Other income/(expense) and Interest expense. to pay ﬁxed amounts rateably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights Derivatives in Qualifying Hedging Relationships are earned by shippers when minimum volume commitments are not The Company uses derivative ﬁnancial instruments to manage utilized during the period but under certain circumstances can be its exposure to changes in commodity prices, foreign exchange used to offset overages in future periods, subject to expiry periods. rates, interest rates and certain compensation tied to its share price. The Company recognizes revenues associated with make-up rights Hedge accounting is optional and requires the Company to document at the earlier of when the make-up volume is shipped, the make-up the hedging relationship and test the hedging item’s effectiveness right expires or when it is determined that the likelihood that in offsetting changes in fair values or cash ﬂows of the underlying the shipper will utilize the make-up right is remote. 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. 118 Enbridge Inc. 2016 Annual Report Cash Flow Hedges The Company uses cash ﬂow hedges to manage its exposure to changes in commodity prices, foreign exchange rates, interest Cash inﬂows and outﬂows related to derivative instruments are classiﬁed as Operating activities on the Consolidated Statements of Cash Flows. rates and certain compensation tied to its share price. The effective Balance Sheet Offset 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. 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. If a derivative instrument designated as a cash ﬂow hedge ceases Transaction Costs to be effective or is terminated, hedge accounting is discontinued Transaction costs are incremental costs directly related to the and the gain or loss at that date is deferred in OCI and recognized acquisition of a ﬁnancial asset or the issuance of a ﬁnancial liability. concurrently with the related transaction. If a hedged anticipated The Company incurs transaction costs primarily from the issuance transaction is no longer probable, the gain or loss is recognized of debt and accounts for these costs as a deduction from Long-term immediately in earnings. Subsequent gains and losses from derivative debt on the Statements of Financial Position. These costs are instruments for which hedge accounting has been discontinued are amortized using the effective interest rate method over the term recognized in earnings in the period in which they occur. of the related debt instrument and are recorded in Interest expense. Fair Value Hedges Equity Investments The Company may use fair value hedges to hedge the fair value Equity investments over which the Company exercises signiﬁcant of debt instruments or commodity positions. The change in the fair inﬂuence, but does not have controlling ﬁnancial interests, are value of the hedging instrument is recorded in earnings with changes accounted for using the equity method. Equity investments are initially in the fair value of the hedged asset or liability that is designated as measured at cost and are adjusted for the Company’s proportionate part of the hedging relationship. If a fair value hedge is discontinued share of undistributed equity earnings or loss. Equity investments are or ceases to be effective, the hedged asset or liability, otherwise increased for contributions made to and decreased for distributions required to be carried at cost or amortized cost, ceases to be received from the investees. To the extent an equity investee remeasured at fair value and the cumulative fair value adjustment undertakes activities necessary to commence its planned principal to the carrying value of the hedged item is recognized in earnings operations, the Company capitalizes interest costs associated with over the remaining life of the hedged item. its investment during such period. Net Investment Hedges Restricted Long-Term Investments Gains and losses arising from translation of net investment Long-term investments that are restricted as to withdrawal in foreign operations from their functional currencies to the or usage, for the purposes of the NEB’s LMCI, are presented Company’s Canadian dollar presentation currency are included as Restricted long-term investments on the Consolidated Statements in cumulative translation adjustments (CTA). The Company of Financial Position. designates foreign currency derivatives and United States dollar denominated debt as hedges of net investments in United States Other Investments dollar denominated foreign operations. As a result, the effective Generally, the Company classiﬁes equity investments in entities portion of the change in the fair value of the foreign currency over which it does not exercise signiﬁcant inﬂuence and that do not derivatives as well as the translation of United States dollar trade on an actively quoted market as other investments carried denominated debt are reﬂected in OCI and any ineffectiveness at cost. Financial assets in this category are initially recorded at fair is reﬂected in current period earnings. Amounts recognized value with no subsequent re-measurement. Any investments which previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassiﬁed to earnings when there is a reduction of the do trade on an active market are classiﬁed as available for sale investments measured at fair value through OCI. Dividends received hedged net investment resulting from disposal of a foreign operation. from investments carried at cost are recognized in earnings when the right to receive payment is established. 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. Notes to the Consolidated Financial Statements 119 Noncontrolling Interests Cash and Cash Equivalents Noncontrolling interests represent ownership interests attributable to Cash and cash equivalents include short-term investments with third parties in certain consolidated subsidiaries, limited partnerships a term to maturity of three months or less when purchased. and VIEs. The portion of equity not owned by the Company in such entities is reﬂected as noncontrolling interests within the equity Restricted Cash section of the Consolidated Statements of Financial Position and, Cash and cash equivalents that are restricted as to withdrawal in the case of redeemable noncontrolling interests, within the or usage, in accordance with speciﬁc commercial arrangements, mezzanine section of the Consolidated Statements of Financial are presented as Restricted cash on the Consolidated Statements Position between long-term liabilities and equity. of Financial Position. The Fund’s noncontrolling interest holders have the option Loans and Receivables 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. 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. On a quarterly basis, changes in estimated redemption values Allowance for Doubtful Accounts are reﬂected as a charge or credit to retained earnings. Allowance for doubtful accounts is determined based on collection The use of the HLBV method by ECT impacts the earnings history. When the Company has determined that further collection attributable to redeemable noncontrolling interests reported efforts are unlikely to be successful, amounts charged to the on Enbridge’s Consolidated Statements of Earnings. allowance for doubtful accounts are applied against the impaired Income Taxes The liability method of accounting for income taxes is followed. accounts receivable. Inventory Deferred income tax assets and liabilities are recorded based Inventory is comprised of natural gas in storage held in EGD on temporary differences between the tax bases of assets and crude oil and natural gas held primarily by energy services and liabilities and their carrying values for accounting purposes. businesses in the Energy Services segment. Natural gas in storage Deferred income tax assets and liabilities are measured using the in EGD is recorded at the quarterly prices approved by the OEB tax rate that is expected to apply when the temporary differences in the determination of distribution rates. The actual price of gas reverse. For the Company’s regulated operations, a deferred income purchased may differ from the OEB approved price. The difference tax liability is recognized with a corresponding regulatory asset between the approved price and the actual cost of the gas purchased to the extent taxes can be recovered through rates. Any interest is deferred as a liability for future refund or as an asset for collection and/or penalty incurred related to tax is reﬂected in Income taxes. as approved by the OEB. Other commodities inventory is recorded Foreign Currency Transactions and Translation at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory Foreign currency transactions are those transactions whose is recorded to Commodity costs on the Consolidated Statements terms are denominated in a currency other than the currency of Earnings at the weighted average cost of inventory, including of the primary economic environment in which the Company any adjustments recorded to reduce inventory to market value. or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are Property, Plant and Equipment translated into the functional currency using the exchange rate Property, plant and equipment is recorded at historical cost. prevailing at the date of transaction. Monetary assets and liabilities Expenditures for construction, expansion, major renewals denominated in foreign currencies are translated to the functional and betterments are capitalized. Maintenance and repair costs currency using the rate of exchange in effect at the balance are expensed as incurred. Expenditures for project development sheet date. Exchange gains and losses resulting from translation are capitalized if they are expected to have future beneﬁt. of monetary assets and liabilities are included in the Consolidated The Company capitalizes interest incurred during construction Statements of Earnings in the period in which they arise. for non rate-regulated assets. For rate-regulated assets, AFUDC 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. 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. 120 Enbridge Inc. 2016 Annual Report Two primary methods of depreciation are utilized. For distinct assets, Impairment 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; and derivative ﬁnancial instruments. Intangible Assets Intangible assets consist primarily of certain software costs, natural gas supply opportunities, acquired power purchase agreements, customer relationships and 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 United States gas systems are located. Customer relationships represent the underlying relationship from long term agreements with customers that are capitalized upon acquisition. 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. 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 cash ﬂows 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 cash ﬂows 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 cash ﬂows. 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. Notes to the Consolidated Financial Statements 121 Effective January 1, 2016, the Company reﬁned the method to For deﬁned contribution plans, contributions made by the Company estimate current service cost and interest cost for pension and other are expensed in the period in which the contribution occurs. postretirement beneﬁts. Previously, these were estimated utilizing a single weighted-average discount rate derived from the yield curve used to measure the deﬁned beneﬁt obligation at the beginning of the year. Under the reﬁned method, different discount rates are derived from the same yield curve, reﬂecting the different timing 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. of beneﬁt payments for past service (the deﬁned beneﬁt obligation) The overfunded or underfunded status of deﬁned beneﬁt pension and future service (the current service cost). Differentiating in this and OPEB plans is recognized as Deferred amounts and other assets, way represents a reﬁnement in the basis of estimation applied in prior Accounts payable and other or Other long-term liabilities, on the periods. This change does not affect the measurement of the total Consolidated Statements of Financial Position. A plan’s funded status deﬁned beneﬁt obligation recorded on the Consolidated Statements is measured as the difference between the fair value of plan assets of Financial Position as at December 31, 2016 or any other period. and the plan’s projected beneﬁt obligation. Any unrecognized actuarial The reﬁnement compared to the previous method resulted in gains and losses and prior service costs and credits that arise during a decrease in the current service cost and interest components the period are recognized as a component of OCI, net of tax. with an equal offset to actuarial gains (losses) with no net impact on the total beneﬁt obligation. The reﬁnement did not have a material impact on the Consolidated Statements of Earnings for the year ended December 31, 2016. This change was accounted for prospectively as a change in accounting estimate. 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 In 2014, new mortality tables were issued by the Society of Actuaries costs are expected to be collected from or refunded to customers, in the United States which were further revised in 2015. These tables, respectively, in future rates. In the absence of rate regulation, along with the Canadian Institute of Actuaries tables that were regulatory balances would not be recorded and pension and OPEB revised in 2013, were used by the Company for measurement of costs would be charged to earnings and OCI on an accrual basis. its beneﬁt obligations of its United States pension plan (the United States Plan) and the Canadian pension plans (the Canadian Plans), Stock-Based Compensation respectively. The Company determines discount rates by reference Incentive Stock Options (ISO) granted are recorded using to rates of high-quality long-term corporate bonds with maturities the fair value method. Under this method, compensation expense that approximate the timing of future payments the Company is measured at the grant date based on the fair value of the ISO anticipates making under each of the respective plans. Pension cost granted as calculated by the Black-Scholes-Merton model and is is charged to earnings and includes: recognized on a straight-line basis over the shorter of the vesting • Cost of pension plan beneﬁts provided in exchange for employee services rendered during the year; 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. • 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 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 • Amortization of cumulative unrecognized net actuarial gains become exercisable when both performance targets and time vesting and losses in excess of 10% of the greater of the accrued beneﬁt obligation or the fair value of plan assets, over the expected requirements have been met. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised. average remaining service life of the active employee group covered by the plans. Performance Stock Units (PSU) and Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured Actuarial gains and losses arise from the difference between each reporting period. PSU vest at the completion of a three-year the actual and expected rate of return on plan assets for that term and RSU vest at the completion of a 35-month term. During the period or from changes in actuarial assumptions used to determine vesting term, compensation expense is recorded based on the number the accrued beneﬁt obligation, including discount rate, changes of units outstanding and the current market price of the Company’s in headcount or salary inﬂation experience. shares with an offset to Accounts payable and other or to Other 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. 122 Enbridge Inc. 2016 Annual Report 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. An estimated loss for commitments and contingencies is 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. 3. Changes in Accounting Policies Adoption of New Standards Classiﬁcation of Deferred Taxes on the Statements of Financial Position Effective January 1, 2016, the Company elected to early adopt Accounting Standards Update (ASU) 2015-17 and applied the standard on a prospective basis. The amendments require that deferred tax liabilities and assets be classiﬁed as noncurrent in the Consolidated Statements of Financial Position. The adoption of the pronouncement did not have a material impact on the Company’s consolidated ﬁnancial statements. Simplifying the Accounting for Measurement-Period Adjustments in Business Combinations Effective January 1, 2016, the Company adopted ASU 2015-16 on a prospective basis. The new standard requires that an acquirer must recognize adjustments to provisional amounts that are identiﬁed during the measurement period in the reporting period in which the adjustment amounts are determined. The adoption of the pronouncement did not have a material impact on the Company’s consolidated ﬁnancial statements. Measurement Date of Deﬁned Beneﬁt Obligation and Plan Assets Effective January 1, 2016, the Company adopted ASU 2015-04 on a prospective basis. The revised criteria simplify the fair value measurement of deﬁned beneﬁt plan assets and obligations. The adoption of the pronouncement did not have a material impact on the Company’s consolidated ﬁnancial statements. Simplifying the Presentation of Debt Issuance Costs Effective January 1, 2016, the Company adopted ASU 2015-03 on a retrospective basis which, as at December 31, 2015, resulted in a decrease in Deferred amounts and other assets of $149 million and a corresponding decrease in Long-term debt of $149 million. The new standard requires debt issuance costs related to a recognized debt liability to be presented in the Consolidated Statements of Financial Position as a direct deduction from the carrying amount of that debt liability, as consistent with the presentation of debt discounts or premiums. ASU 2015-15 was adopted in conjunction with the above standard and did not have a material impact on the Company’s consolidated ﬁnancial statements. ASU 2015-15 clariﬁes the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements, whereby an entity may defer debt issuance costs as an asset and subsequently amortize them over the term of the line-of-credit. Notes to the Consolidated Financial Statements 123 Amendments to the Consolidation Analysis Accounting for Intra-Entity Asset Transfers Effective January 1, 2016, the Company adopted ASU 2015-02 ASU 2016-16 was issued in October 2016 with the intent on a modiﬁed retrospective basis, which amended and clariﬁed the of improving the accounting for the income tax consequences guidance on VIEs. There was a signiﬁcant change in the assessment of intra-entity asset transfers other than inventory. Under the new of limited partnerships and other similar legal entities as VIEs, guidance, an entity should recognize the income tax consequences including the removal of the presumption that the general partner of an intra-entity transfer of an asset, other than inventory, when should consolidate a limited partnership. As a result, the Company the transfer occurs. The accounting update is effective for annual has determined that a majority of the limited partnerships that are and interim periods beginning on or after December 15, 2017 and currently consolidated or equity accounted for are VIEs. The amended is to be applied on a modiﬁed retrospective basis, with early adoption guidance did not impact the Company’s accounting treatment of such permitted. Effective January 1, 2017, the Company elected to early entities, however, material disclosures for VIEs have been provided, adopt ASU 2016-16. The adoption of the pronouncement is not as necessary. anticipated to have a material impact on the Company‘s consolidated Hybrid Financial Instruments Issued in the Form of a Share Effective January 1, 2016, the Company adopted ASU 2014-16 ﬁnancial statements. Simplifying Cash Flow Classiﬁcation on a modiﬁed retrospective basis. The revised criteria eliminate ASU 2016-15 was issued in August 2016 with the intent of reducing the use of different methods in practice in the accounting for diversity in practice of how certain cash receipts and cash payments hybrid ﬁnancial instruments issued in the form of a share. The new are classiﬁed in the Consolidated Statements of Cash Flows. standard clariﬁes the evaluation of the economic characteristics The new guidance addresses eight speciﬁc presentation issues. and risks of a host contract in these hybrid ﬁnancial instruments. The Company is currently assessing the impact of the new standard The adoption of the pronouncement did not have a material impact on its consolidated ﬁnancial statements. The accounting update on the Company’s consolidated ﬁnancial statements. is effective for annual and interim periods beginning on or after Development Stage Entities December 15, 2017 and is to be applied on a retrospective basis. Effective January 1, 2016, the Company adopted ASU 2014-10 Accounting for Credit Losses on a retrospective basis. The new standard amends the consolidation ASU 2016-13 was issued in June 2016 with the intent of providing guidance to eliminate the development stage entity relief when ﬁnancial statement users with more useful information about the applying the VIE model and evaluating the sufficiency of equity expected credit losses on ﬁnancial instruments and other commitments at risk. The adoption of the pronouncement did not have a material to extend credit held by a reporting entity at each reporting date. impact on the Company’s consolidated ﬁnancial statements. Current treatment uses the incurred loss methodology for recognizing Future Accounting Policy Changes credit losses that delays the recognition until it is probable a loss has been incurred. The amendment adds a new impairment model, known Clarifying the Deﬁnition of a Business in an Acquisition as the current expected credit loss model that is based on expected ASU 2017-01 was issued in January 2017 with the intent of clarifying the deﬁnition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) of assets or businesses. The Company is currently assessing the impact of the new standard on the consolidated ﬁnancial statements. The accounting update is effective for annual and interim periods beginning on or after losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The Company is currently assessing the impact of the new standard on its consolidated ﬁnancial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019. December 15, 2017 and is to be applied on a prospective basis. Improvements to Employee Share-Based Payment Accounting ASU 2016-09 was issued in March 2016 with the intent of simplifying and improving several aspects of accounting for share-based payment transactions including the income tax consequences, classiﬁcation of awards as either equity or liabilities, and classiﬁcation on the Consolidated Statements of Cash Flows. The accounting update is effective for annual and interim periods beginning on or after December 15, 2016 and is to be applied on a prospective or retrospective basis. The adoption of the pronouncement is not anticipated to have a material impact on the Company’s consolidated ﬁnancial statements. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows ASU 2016-18 was issued in November 2016 with the intent to add or clarify guidance on the classiﬁcation and presentation of changes in restricted cash and restricted cash equivalents within the cash ﬂow statement. The amendments require that changes in restricted cash and restricted cash equivalents should be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash ﬂows. The Company is currently assessing the impact of the new standard on its consolidated ﬁnancial statements. The accounting update is effective for ﬁscal years beginning after December 15, 2017 and is to be applied on a retrospective basis. 124 Enbridge Inc. 2016 Annual Report Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the Consolidated Statements of Financial Position and disclosing additional key information about leasing arrangements. The Company is currently assessing the impact of the new standard on its consolidated ﬁnancial statements. The accounting update is effective for ﬁscal years beginning after December 15, 2018, and is to be applied using a modiﬁed retrospective approach. Recognition and Measurement of Financial Assets and Liabilities ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation, and disclosure of ﬁnancial assets and liabilities. The amendments revise accounting related to the classiﬁcation and measurement of investments in equity securities, the presentation of certain fair value changes for ﬁnancial liabilities measured at fair value, and the disclosure requirements associated with the fair value of ﬁnancial instruments. The Company is currently assessing the impact of the new standard on its consolidated ﬁnancial statements. The accounting update is effective for ﬁscal years beginning after December 15, 2017, and is to be applied by means of a cumulative- effect adjustment to the Statements of Financial Position as of the beginning of the ﬁscal year of adoption, with amendments related to equity securities without readily determinable fair values to be applied prospectively. Revenue from Contracts with Customers ASU 2014-09 was issued in 2014 with the intent of signiﬁcantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based ﬁve-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective January 1, 2018. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modiﬁed retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. The Company is currently assessing which transition method to use. The Company has reviewed a sample of its revenue contracts in order to evaluate the effect of the new standard on its revenue recognition practices. Based on the Company’s initial assessment, the application of the standard may result in a change in presentation in the Gas Distribution business related to payments to customers under the earnings sharing mechanism which are currently shown as an expense in the Consolidated Statements of Earnings. Under the new standard, these payments would be reﬂected as a reduction of revenue. Additionally, estimates of variable consideration which will be required under the new standard for certain Liquids Pipelines, Gas Pipelines and Processing and Green Power and Transmission revenue contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts. While the Company has not yet completed the assessment, the Company‘s preliminary view is that it does not expect these changes will have a material impact on revenue or earnings (loss). The Company is also developing processes to generate the disclosures required under the new standard. 4. Segmented Information Effective January 1, 2016, the Company revised its reportable segments. Revisions to the segmented information presentation on a retrospective basis include: • The replacement of the previous segments: Liquids Pipelines; Gas Distribution; Gas Pipelines, Processing and Energy Services; Sponsored Investments; and Corporate with new segments: Liquids Pipelines; Gas Distribution; Gas Pipelines and Processing; Green Power and Transmission; and Energy Services; and • Presenting the Earnings before interest and income taxes of each segment as opposed to Earnings attributable to Enbridge Inc. common shareholders. Amounts related to Interest expense, Income taxes, Earnings attributable to noncontrolling interests and redeemable noncontrolling interests and Preference share dividends are now reported on a consolidated basis. On May 12, 2016, the Company ﬁled amended ﬁnancial statements for the year ended December 31, 2015 to retrospectively apply the revisions of its reportable segments to the 2015 ﬁnancial statements of the Company that were previously ﬁled on February 19, 2016. Notes to the Consolidated Financial Statements 125 Segmented information for the years ended December 31, 2016, 2015 and 2014 are as follows: Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other Consolidated 8,176 (12) (2,910) (1,369) 2 (1,365) 2,522 194 841 3,557 2,976 (1,653) (553) (339) – – 431 12 49 492 2,877 (2,206) (447) (292) – (11) (79) 223 27 171 502 5 (173) (190) – – 144 2 8 154 20,364 (20,473) (63) (2) – – (174) (3) (8) (335) 334 (214) (48) – – (263) – 115 (185) (148) 3,957 52,043 713 10,204 176 11,182 251 5,571 – 32 1,951 4,881 85,832 Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other Consolidated 5,589 (9) (2,769) (1,227) 21 (80) – 1,525 296 (15) 3,609 (2,349) (536) (308) – – – 416 (10) 49 1,806 455 3,803 (3,002) (506) (272) – (16) (440) (433) 200 4 (229) 498 4 (143) (186) – – – 173 2 2 177 20,842 (20,443) (66) 1 – – – 334 (9) – 325 (547) 558 (132) (32) – – – (153) (4) (742) (899) Year ended December 31, 2016 (millions of Canadian dollars) Revenues Commodity and gas distribution costs Operating and administrative Depreciation and amortization Environmental costs, net of recoveries Impairment of property, plant and equipment Income/(loss) from equity investments Other income/(expense) Earnings/(loss) before interest and income taxes Interest expense Income taxes Earnings Earnings attributable to noncontrolling interests and redeemable noncontrolling interests Preference share dividends Earnings attributable to Enbridge Inc. common shareholders Additions to property, plant and equipment1 Total assets Year ended December 31, 2015 (millions of Canadian dollars) Revenues Commodity and gas distribution costs Operating and administrative Depreciation and amortization Environmental costs, net of recoveries Impairment of property, plant and equipment Goodwill impairment Income/(loss) from equity investments Other income/(expense) Earnings/(loss) before interest and income taxes Interest expense Income taxes Loss Loss attributable to noncontrolling interests and redeemable noncontrolling interests Preference share dividends Loss attributable to Enbridge Inc. common shareholders 34,560 (24,005) (4,360) (2,240) 2 (1,376) 2,581 428 1,032 4,041 (1,590) (142) 2,309 (240) (293) 1,776 5,129 33,794 (25,241) (4,152) (2,024) 21 (96) (440) 1,862 475 (702) 1,635 (1,624) (170) (159) 410 (288) (37) 7,275 84,515 Additions to property, plant and equipment1 Total assets 5,884 52,015 858 9,901 385 11,559 68 4,977 – 1,889 80 4,174 126 Enbridge Inc. 2016 Annual Report Year ended December 31, 2014 (millions of Canadian dollars) Revenues Commodity and gas distribution costs Operating and administrative Depreciation and amortization Environmental costs, net of recoveries Income/(loss) from equity investments Other income/(expense) Earnings/(loss) before interest and income taxes Interest expense Income taxes Earnings from continuing operations Discontinuing operations Earnings from discontinued operations before income taxes Income taxes from discontinued operations Earnings from discontinued operations Earnings Earnings attributable to noncontrolling interests and redeemable noncontrolling interests Preference share dividends Earnings attributable to Enbridge Inc. common shareholders Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other Consolidated 4,805 (1) (1,985) (911) (100) 1,808 161 11 3,319 (2,082) (531) (304) – 402 (14) 44 1,980 432 6,650 (5,686) (533) (221) – 210 224 33 467 360 3 (94) (124) – 145 3 1 23,099 (22,314) (58) 2 – 729 – 1 149 730 (592) 597 (80) (19) – (94) (6) (356) (456) 37,641 (29,483) (3,281) (1,577) (100) 3,200 368 (266) 3,302 (1,129) (611) 1,562 73 (27) 46 1,608 (203) (251) 1,154 10,527 Additions to property, plant and equipment1 8,914 610 593 333 3 74 1 Includes allowance for equity funds used during construction. 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 in respect of an overstatement of deferred income tax expense in 2013 and 2014. Geographic Information Revenues1 Year ended December 31, (millions of Canadian dollars) Canada United States 1 Revenues are based on the country of origin of the product or service sold. Property, Plant and Equipment December 31, (millions of Canadian dollars) Canada United States 2016 2015 2014 12,470 22,090 34,560 11,087 22,707 33,794 14,963 22,678 37,641 2016 2015 32,008 32,276 64,284 30,656 33,778 64,434 Notes to the Consolidated Financial Statements 127 Gas Distribution Enbridge Gas Distribution EGD’s gas distribution operations are regulated by the OEB. Rates for the years ended December 31, 2016 and 2015 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. EGD’s after-tax rate of return on common equity embedded in rates was 9.2% for the year ended December 31, 2016 (2015 – 9.3%) based on a 36% (2015 – 36%) deemed common equity component of capital for regulatory purposes. Enbridge Gas New Brunswick Enbridge Gas New Brunswick Inc. is regulated by the EUB and currently sets tolls at either market-based or cost of service rates. 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 by the NEB. The Company also collects and sets aside funds to cover future pipeline abandonment costs for all NEB regulated pipelines as a result of the NEB’s regulatory requirements under LMCI (Note 12). Amounts expected to be paid to cover future abandonment costs are recognized as long-term regulatory liabilities. The Company’s signiﬁcant regulated businesses and other related accounting impacts, are described below. Liquids Pipelines 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 the Canadian portion of the Southern Lights Pipeline (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. 128 Enbridge Inc. 2016 Annual Report Financial Statement Effects Accounting for rate-regulated activities has resulted in the recognition of the following signiﬁcant regulatory assets and liabilities: December 31, (millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines Deferred income taxes1 Tolling deferrals2 Recoverable income taxes3 Pipeline future abandonment costs4 Transportation revenue adjustments5 Gas Distribution Deferred income taxes6 Purchased gas variance7 Pension plans and OPEB8 Constant dollar net salvage adjustment9 Unabsorbed demand cost10 Future removal and site restoration reserves11 Site restoration clearance adjustment12 Transaction services deferral13 2016 2015 1,270 1,048 (37) 51 (88) – 385 5 116 38 – (606) (109) (4) (39) 54 (47) 11 328 129 104 42 66 (581) (193) (9) 1 The deferred income tax asset represents the regulatory offset to deferred income tax liabilities that are expected to be recovered under ﬂow-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 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. 6 The deferred income tax asset represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in regulator-approved future rates and recovered from future customers. The recovery period depends on the timing of the reversal of the temporary differences. 7 Purchased gas variance (PGVA) is the difference between the actual cost and the approved cost of natural gas reﬂected in rates. Enbridge Gas Distribution 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 balance as at June 30, 2014 to be recovered over a 24-month period from July 1, 2014 to June 30, 2016. 8 The pension plans and OPEB balances represent the regulatory offset 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, 2016 was $71 million (2015 – $75 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. 9 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 clearance adjustment. At the end of 2018, any residual balance will be cleared in a post 2018 true up. 10 The unabsorbed demand cost deferral account represents the actual cost consequences of unutilized transportation capacity contracted by Enbridge Gas Distribution to meet requirements resulting from its Peak Gas Design Day Criteria. 11 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. 12 The site restoration clearance adjustment represents the amount, that was determined by the OEB, of previously collected costs for future removal and site restoration that is now considered to be in excess of future requirements and will be refunded to customers over the customized IR term. This was a result of the OEB’s approval of the adoption of a new approach for determining net negative salvage percentages. The new approach resulted in lower depreciation rates and lower future removal and site restoration reserves. 13 The transaction services deferral represents the customer portion of additional earnings generated from optimization of storage and pipeline capacity. Enbridge Gas Distribution has historically been required to refund the amount to customers in the following year. 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. Notes to the Consolidated Financial Statements 129 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, 2016, cumulative costs relating to this consulting contract of $181 million (2015 – $179 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. Acquisition and Dispositions Acquisitions Spectra Energy Corp On September 6, 2016 Enbridge and Spectra Energy Corp (Spectra Energy) announced that they had entered into a deﬁnitive merger agreement under which Enbridge and Spectra Energy would combine in a stock-for-stock merger transaction (the Merger Transaction). The Merger Transaction was unanimously approved by the Boards of Directors and shareholders of both companies. Shareholders’ approval for both companies was received in December 2016 and the Merger Transaction is expected to close in the ﬁrst quarter of 2017, subject to certain regulatory approvals and other customary conditions. Under the terms of the Merger Transaction, Spectra Energy shareholders will receive 0.984 shares of the combined company for each share of Spectra Energy common stock they own. Upon completion of the Merger Transaction, Enbridge shareholders are expected to own approximately 57% of the combined company and Spectra Energy shareholders are expected to own approximately 43%. The combined company will be called Enbridge Inc. Tupper Main and Tupper West On April 1, 2016, Enbridge acquired the Tupper Main and Tupper West gas plants and associated pipelines (the Tupper Plants) located in northeastern British Columbia for cash consideration of $539 million. The purchase price for the Tupper Plants was equal to the fair value of identiﬁable net assets acquired and accordingly, the Company did not recognize any goodwill as part of the acquisition. Transaction costs incurred by the Company totalled approximately $1 million and are included in Operating and administrative expense within the Consolidated Statements of Earnings. The Tupper Plants are included within the Gas Pipelines and Processing segment. Since the closing date through December 31, 2016, the Tupper Plants have generated approximately $33 million in revenues and $22 million in earnings before interest and income taxes. If the acquisition had closed on January 1, 2016, the Consolidated Statements of Earnings for the years ended December 31, 2016, would have shown revenues of $44 million and earnings before interest and income taxes of $28 million, respectively. The ﬁnal purchase price allocation was as follows: April 1, (millions of Canadian dollars) Fair value of net assets acquired: Property, plant and equipment Intangible assets Purchase price: Cash 130 Enbridge Inc. 2016 Annual Report 2016 288 251 539 539 Midstream Business On February 27, 2015, Enbridge Energy Partners, L.P. (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 Gas Pipelines and Processing 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, 2015, changes to revenues and earnings for the years ended December 31, 2016 and 2015 would have been nominal. The ﬁnal purchase price allocation was as follows: February 27, (millions of Canadian dollars) Fair value of net assets acquired: Property, plant and equipment Intangible assets Purchase price: Cash Contingent consideration1 2015 69 40 109 106 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 contingent future consideration at the acquisition date was $3 million (US$2 million). During the ﬁrst quarter of 2016, and upon subsequent reassessments, MEP determined, based on current and forecasted volumes, that it is remote that MEP will be obligated to make any payments at the expiration of the ﬁve-year period. Consequently, the liability was reversed and a $4 million (US$3 million) gain was recognized as a reduction to “Operating and administrative” expense, which is reﬂected in the consolidated statements of income for the year ended December 31, 2016. Magic Valley and Wildcat Wind Farms 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 Green Power and Transmission segment. 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 ﬁnal purchase price allocation was a follows: December 31, (millions of Canadian dollars) Fair value of net assets acquired: Property, plant and equipment Intangible assets Other long-term liabilities Noncontrolling interests1 Purchase price: Cash 2014 747 12 (14) (351) 394 394 1 The fair value of the noncontrolling interests was determined using a combination of the implied purchase price for the remaining 20% interest and discounted cash ﬂow models. Notes to the Consolidated Financial Statements 131 Other Acquisitions Chapman Ranch Wind Project On September 9, 2016, the Company acquired a 100% interest in the 249 megawatt (MW) Chapman Ranch Wind Project (Chapman Ranch) located in Texas for cash consideration of $65 million (US$50 million), of which $62 million (US$48 million) was allocated to Property, plant and equipment and the balance allocated to Intangible assets. On November 2, 2016, the Company invested a further $40 million (US$30 million) in Chapman Ranch, of which $23 million (US$17 million) was related to Property, plant and equipment and the balance related to Intangible assets. There would have been no effect on earnings if the transaction had occurred on January 1, 2016 as the project is under construction and has not generated revenues to date. Chapman Ranch is included within the Green Power and Transmission segment. Other In November 2015, the Company acquired a 100% interest in the 103 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 was placed into 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. The New Creek, Massif du Sud and Lac Alfred wind projects are included within the Green Power and Transmission segment. Assets Held for Sale In December 2016, the Company entered into an agreement to sell the Ozark Pipeline assets to a subsidiary of MPLX LP for cash proceeds of approximately $294 million (US$219 million), including $13 million (US$10 million) in reimbursable capital costs up to the closing date of the transaction. Subject to certain pre-closing conditions, the transaction is expected to close by the end of the ﬁrst quarter of 2017. The Ozark Pipeline is included within the Company’s Liquids Pipelines segment. As at December 31, 2016, the assets of Ozark Pipeline were classiﬁed as held for sale and were measured at the lower of their carrying value or fair value less costs to sell, which did not result in a fair value adjustment. Included within Assets held for sale on the Consolidated Statements of Financial Position was $278 million (US$207 million) related to Property, plant and equipment. Dispositions South Prairie Region On December 1, 2016, the Company completed the sale of the South Prairie Region assets to an unrelated party for cash proceeds of $1.08 billion. A gain on sale of $850 million before tax was recognized in Other income/(expense) on the Consolidated Statements of Earnings. The South Prairie Region assets were included within the Company’s Liquids Pipelines segment. For the year ended December 31, 2016, pre-tax earnings for the South Prairie Region assets were $41 million. Other Dispositions In December 2016, the Company sold other miscellaneous non-core assets for cash proceeds of $286 million. 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 income/(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 within the Liquids Pipelines segment to an unrelated party for gross proceeds of $26 million. A gain of $22 million was presented within Other income/(expense) on the Consolidated Statements of Earnings. 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 income/(expense) on the Consolidated Statements of Earnings. These assets were included within the Gas Pipelines and Processing segment. In July 2014, the Company sold a 35% equity interest in the Southern Access Extension Project within the Liquids Pipelines segment, 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. In March 2014, the Company sold an Alternative and Emerging Technologies investment within Eliminations and Other to an unrelated party for $19 million. A gain of $16 million was presented within Other income/(expense) on the Consolidated Statements of Earnings. 132 Enbridge Inc. 2016 Annual Report 7. Accounts Receivable and Other December 31, (millions of Canadian dollars) Unbilled revenues Trade receivables Taxes receivable Regulatory assets Short-term portion of derivative assets (Note 24) Prepaid expenses and deposits Current deferred income taxes (Note 25) Dividends receivable Rebillable receivables Agent billing and collection receivable Other Allowance for doubtful accounts Pursuant to a Receivables Purchase Agreement (the Receivables Agreement) executed in 2013, certain trade and accrued receivables (the Receivables) have been sold by certain EEP 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 was amended in June 2016 to extend the termination date that provides for purchases to occur on a monthly basis through to December 2019, provided accumulated purchases net of collections do not exceed US$450 million at any one point. The value of trade and accrued receivables outstanding owned by the SPE totalled US$355 million ($477 million) and US$317 million ($439 million) as at December 31, 2016 and December 31, 2015, respectively. 8. Inventory December 31, (millions of Canadian dollars) Natural gas Crude oil Other commodities 2016 2015 2,886 974 222 66 353 168 – 26 63 35 231 (46) 4,978 2,476 1,079 175 216 791 181 367 26 – 39 125 (45) 5,430 2016 594 634 5 1,233 2015 627 477 7 1,111 Notes to the Consolidated Financial Statements 133 9. Property, Plant and Equipment December 31, (millions of Canadian dollars) Liquids Pipelines Pipeline Pumping equipment, buildings, tanks and other Land and right-of-way Under construction Accumulated depreciation Gas Distribution Gas mains, services and other Land and right-of-way Under construction Accumulated depreciation Gas Pipelines and Processing Pipeline Compressors, meters and other operating equipment Processing and treating plants Pumping equipment, buildings, tanks and other Land and right-of-way Under construction Accumulated depreciation Green Power and Transmission Wind turbines, solar panels and other Power transmission Land and right-of-way Under construction Accumulated depreciation Energy Services Pumping equipment and other Accumulated depreciation Eliminations and Other Vehicles, office furniture, equipment and other Accumulated depreciation Weighted Average Depreciation Rate 2016 2015 2.7% 3.0% 2.4% – 3.1% 1.0% – 3.0% 2.4% 2.4% 8.4% 2.3% – 4.1% 2.2% 1.9% – 4.0% 9.3% 30,809 15,215 1,218 5,419 52,661 (8,996) 43,665 10,022 133 144 10,299 (2,524) 7,775 3,665 4,014 846 306 673 791 10,295 (2,167) 8,128 4,259 378 43 612 5,292 (778) 4,514 33 33 (13) 20 315 315 (133) 182 31,092 14,319 1,221 6,002 52,634 (8,233) 44,401 8,819 85 902 9,806 (2,379) 7,427 3,557 3,864 869 275 680 956 10,201 (2,003) 8,198 4,311 387 45 51 4,794 (600) 4,194 34 34 (13) 21 331 331 (138) 193 Depreciation expense for the year ended December 31, 2016 was $2,049 million (2015 – $1,852 million; 2014 – $1,461 million). 64,284 64,434 134 Enbridge Inc. 2016 Annual Report Impairment Discontinued Operations Northern Gateway Pipeline Project On November 29, 2016, the Canadian Federal Government directed the NEB to dismiss the Company’s Northern Gateway application and the Certiﬁcates of Public Convenience and Necessity have been rescinded. In consultation with potential shippers and Aboriginal equity partners, the Company assessed this decision and concluded that the project cannot proceed as envisioned. After taking into consideration the amount recoverable from potential shippers on Northern Gateway, the Company recognized an impairment of $373 million ($272 million after-tax), which is included in Impairment of property, plant and equipment in the Consolidated Statements of Earnings. This impairment loss is based on the full carrying value of the assets, which have an estimated fair value of nil, and is included within the Liquids Pipelines segment. Sandpiper Project On September 1, 2016, Enbridge announced that EEP applied for the withdrawal of regulatory applications pending with the Minnesota Public Utilities Commission for the Sandpiper Project (Sandpiper). In connection with this announcement and other factors, the Company evaluated Sandpiper for impairment. As a result, the Company recognized an impairment loss of $992 million ($81 million after-tax attributable to Enbridge) for the year ended December 31, 2016, which is included in Impairment of property, plant and equipment in the Consolidated Statements of Earnings. Sandpiper is included within the Liquids Pipelines segment. The estimated remaining fair value of $71 million of Sandpiper is based on the estimated price that would be received to sell unused pipe, land and other related equipment in its current condition, considering the current market conditions for sale of these assets. The valuation considered a range of potential selling prices from various alternatives that could be used to dispose of these assets. The estimated fair value, with the exception of $3 million in land, has been reclassiﬁed into Deferred amounts and other assets in the Consolidated Statements of Financial Position as at December 31, 2016. Other For the year ended December 31, 2016, the Company recorded impairment charges of $11 million related to EEP’s non-core trucking assets and related facilities, included within the Gas Pipelines and Processing segment. For the year ended December 31, 2015, the Company recorded impairment charges of $96 million, of which $80 million related to EEP’s Berthold rail facility, included within the Liquids Pipelines segment, 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, included within the Gas Pipelines and Processing segment, following ﬁnalization of a contract restructuring with the primary customer. Impairment charges were based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash ﬂows, and were presented within Impairment of property, plant and equipment on the Consolidated Statements of Earnings. 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 related cash ﬂows, have also been presented as discontinued operations for the year ended December 31, 2014. These Offshore assets were included within the Gas Pipelines and Processing segment. 10. Variable Interest Entities Consolidated Variable Interest Entities Enbridge Energy Partners, L.P. EEP is a publicly-traded Delaware limited partnership and is considered a VIE as its limited partners do not have substantive kick-out rights or participating rights. Enbridge, through its wholly- owned subsidiary, Enbridge Energy Company, Inc. (EECI), has the power to direct EEP’s activities that have a signiﬁcant impact on EEP’s economic performance. Along with a 35.3% (2015 – 35.7%; 2014 – 33.7%) economic interest held through an indirect common interest and preferred unit interest through EECI, the Company, through its 100% ownership of EECI, is the primary beneﬁciary of EEP. The public owns the remaining interests in EEP. 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 86.9% (2015 – 89.2%; 2014 – 66.4%) 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. As at December 31, 2016, the Company’s direct common interest in the Fund was 43.2% (2015 – 49.2%; 2014 – 11.9%). Enbridge also serves in the capacity of Manager of ENF and the Fund Group. Enbridge Commercial Trust Enbridge has the ability to appoint the majority of the Trustees to ECT 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. Enbridge Income Partners LP EIPLP, formed in 2002, is involved in the generation, transportation and storage of energy through interests in its Liquids Pipelines business, including the Canadian Mainline, the Regional Oil Sands System, a 50.0% interest in the Alliance Pipeline, which transports Notes to the Consolidated Financial Statements 135 natural gas, and its renewable and alternative power generation facilities. EIPLP is a partnership between an indirect wholly-owned subsidiary of the Company and ECT. EIPLP is considered a VIE as its limited partners lack substantive kick-out rights and participating rights. Through a majority ownership of EIPLP’s General Partner, 100% ownership of Enbridge Management Services Inc. (a service provider for EIPLP), and 54.2% of direct common interest in EIPLP, the Company has the power to direct the activities that most signiﬁcantly impact EIPLP’s economic performance and has the obligation to absorb losses and the right to receive residual returns that are potentially signiﬁcant to EIPLP, making the Company the primary beneﬁciary of EIPLP. As at December 31, 2016, the Company’s economic interest in EIPLP was 79.1%. Green Power and Transmission Through various subsidiaries, Enbridge has majority ownership interest in Magic Valley, Wildcat, Keechi, and New Creek wind farms. These wind farms are considered VIEs as they do not have sufficient equity at risk and are partially ﬁnanced by tax equity investors. Enbridge is the primary beneﬁciary of these 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 its obligation to absorb losses. Other Limited Partnerships By virtue of a lack of substantive kick-out rights and participating rights, substantially all limited partnerships wholly-owned by Enbridge and/or its subsidiaries are considered VIEs. As these entities are 100% owned and directed by Enbridge with no third parties having the ability to direct any of the signiﬁcant activities, the Company is considered the primary beneﬁciary. The following table includes assets to be used to settle liabilities of Enbridge’s consolidated VIEs and liabilities of Enbridge’s consolidated VIEs for which creditors do not have recourse to the Company’s general credit as the primary beneﬁciary. These assets and liabilities are included in the Consolidated Statements of Financial Position. December 31, (millions of Canadian dollars) Assets Cash and cash equivalents Restricted cash Accounts receivable and other Accounts receivable from affiliates Inventory Property, plant and equipment, net Long-term investments Restricted long-term investments Deferred amounts and other assets Intangible assets, net Goodwill Deferred income taxes Assets held for sale Liabilities Bank indebtedness Accounts payable and other Accounts payable to affiliates Interest payable Environmental liabilities Current maturities of long-term debt Long-term debt Other long-term liabilities Deferred income taxes Net assets before noncontrolling interests 136 Enbridge Inc. 2016 Annual Report 2016 2015 486 – 781 3 53 1,323 45,720 954 83 1,949 488 29 231 278 362 26 972 29 54 1,443 45,882 1,005 45 1,806 525 29 267 – 51,055 51,002 172 1,446 105 204 140 342 2,409 20,176 1,207 1,753 25,545 25,510 33 2,077 92 202 139 760 3,303 19,998 1,340 1,253 25,894 25,108 The Company does not have an obligation to provide ﬁnancial support to any of the consolidated VIEs, with the exception of EIPLP. The Company is required, when called on by Enbridge Income Fund Holdings Inc., to backstop equity funding required by EIPLP to undertake the growth program embedded in the assets it acquired in the Canadian Restructuring Plan. Unconsolidated Variable Interest Entities The Company currently holds several equity investments in limited partnerships that are assessed to be VIEs due to limited partners not having substantive kick-out rights or participating rights. Enbridge has determined that it does not have the power to direct the activities of the VIEs that most signiﬁcantly impact the VIEs’ economic performance. Speciﬁcally, the power to direct the activities of a majority of these VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee who makes signiﬁcant decisions for the VIE and none of the partners may make major decisions unilaterally. The carrying amount of the Company’s interest in VIEs that are unconsolidated and its estimated maximum exposure to loss as at December 31, 2016 and 2015 is presented below. December 31, 2016 (millions of Canadian dollars) Vector Pipeline L.P.4 Aux Sable Liquid Products L.P.2 Rampion Offshore Wind Limited3 Eddystone Rail Company, LLC4 Illinois Extension Pipeline Company, L.L.C.1 Eolien Maritime France SAS5 Other1 December 31, 2015 (millions of Canadian dollars) Vector Pipeline L.P.4 Aux Sable Liquid Products L.P.1 Rampion Offshore Wind Limited3 Eddystone Rail Company, LLC4 Illinois Extension Pipeline Company, L.L.C.1 Other1 Carrying Amount of Investment in VIE Enbridge’s Maximum Exposure to Loss 159 158 345 19 759 58 17 289 223 457 25 759 686 17 1,515 2,456 Carrying Amount of Investment in VIE Enbridge’s Maximum Exposure to Loss 159 175 201 168 713 15 308 175 403 220 713 15 1,431 1,834 1 At December 31, 2016, the maximum exposure to loss for these entities is limited to the Company’s equity investment as these companies are in operation and self-sustaining. 2 At December 31, 2016, the maximum exposure to loss includes a guarantee by the Company for its respective share of the VIE’s borrowing on a bank credit facility. 3 At December 31, 2016, the maximum exposure to loss includes the portion of the Company’s parental guarantee that has been committed in project construction contracts in which the Company would be liable for in the event of default by the VIE. 4 At December 31, 2016 the maximum exposure to loss includes the carrying value of an outstanding loan issued by the Company. 5 At December 31, 2016, the maximum exposure to loss includes the portion of the Company’s parental guarantee that has been committed in project construction contracts in which the Company would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $136 million held by the Company. The Company does not have an obligation to and did not provide any additional ﬁnancial support to the VIEs during the year ended December 31, 2016. Notes to the Consolidated Financial Statements 137 11. Long-Term Investments December 31, (millions of Canadian dollars) Equity Investments Liquids Pipelines Seaway Crude Pipeline System Southern Access Extension Project Enbridge Rail (Philadelphia) L.L.C. Other Gas Distribution Noverco Common Shares Gas Pipelines and Processing Texas Express Pipeline Alliance Pipeline Aux Sable Vector Pipeline Offshore – various joint ventures Other Green Power and Transmission Rampion offshore wind project1 Eolien Maritime France SAS2 Other Eliminations and Other Other Other Long-Term Investments Gas Distribution Noverco Preferred Shares Green Power and Transmission Emerging Technologies and Other Eliminations and Other Other Ownership Interest 2016 2015 50.0% 65.0% 75.0% 30.0% – 43.9% 38.9% 35.0% 50.0% 42.7% – 50.0% 60.0% 22.0% – 74.3% 33.3% – 70.0% 24.9% 50.0% 18.9% – 50.0% 19.0% – 42.7% 3,129 759 19 70 – 484 411 324 159 435 4 345 58 100 15 355 90 79 6,836 3,251 713 168 69 – 515 427 344 159 479 12 201 – 109 12 359 106 84 7,008 1 On November 4, 2015, Enbridge acquired a 24.9% equity interest in Rampion Offshore Wind Limited. 2 On May 19, 2016, Enbridge acquired a 50% equity interest in Eolien Maritime France SAS. 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 $859 million (2015 – $885 million) in Goodwill and $687 million (2015 – $568 million) in amortizable assets. For the year ended December 31, 2016, dividends received from equity investments was $825 million (2015 – $719 million; 2014 – $564 million). 138 Enbridge Inc. 2016 Annual Report Summarized combined ﬁnancial information of the Company’s interest in unconsolidated equity investments is as follows: Year ended December 31, (millions of Canadian dollars) Revenues Commodity costs Operating and administrative expense Depreciation and amortization Other income/(expense) Interest expense Earnings before income taxes December 31, (millions of Canadian dollars) Current assets Property, plant and equipment, net Deferred amounts and other assets Intangible assets, net Goodwill Current liabilities Long-term debt Other long-term liabilities Net assets Alliance Pipeline 2016 2015 2014 1,761 1,557 1,790 (385) (545) (293) (41) (69) 428 (369) (376) (274) 4 (67) 475 (661) (444) (232) (1) (84) 368 2016 2015 464 6,534 47 118 862 (433) (792) (488) 6,312 389 6,602 40 64 885 (500) (854) (167) 6,459 Certain assets of the Alliance Pipeline are pledged as collateral to Alliance Pipeline lenders. Noverco As at December 31, 2016, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2015 – 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 margin of 4.38%. As at December 31, 2016, Noverco owned an approximate 3.4% (2015 – 3.6%; 2014 – 3.6%) reciprocal shareholding in common shares of Enbridge. Through secondary offerings, Noverco purchased 1.2 million common shares in February 2016 and sold 1.3 million common shares in 2014. Shares purchased and sold in these transactions were treated as 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 1.3% (2015 – 1.4%; 2014 – 1.4%) in its own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $102 million at December 31, 2016 (2015 – $83 million; 2014 – $83 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. Eddystone Rail Company, LLC During the year ended December 31, 2016, the Company recorded an investment impairment of $184 million related to Enbridge’s 75% joint venture interest in Eddystone Rail Company, LLC (Eddystone Rail), which is held through Enbridge Rail (Philadelphia) L.L.C., a wholly-owned subsidiary. Eddystone Rail is a rail-to-barge transloading facility located in the greater Philadelphia, Pennsylvania area that delivers Bakken and other light sweet crude oil to Philadelphia area reﬁneries. Due to a signiﬁcant decrease in price spreads between Bakken crude oil and West Africa/Brent crude oil and increased competition in the region, demand for Eddystone Rail services dropped signiﬁcantly, which led to the completion of an impairment test. The impairment charge is presented within Income from equity investments on the Consolidated Statements of Earnings. The investment in Eddystone Rail is included within the Liquids Pipelines segment. Notes to the Consolidated Financial Statements 139 The impairment charge was based on the amount by which the carrying value of the asset exceeded fair value, determined using an adjusted net worth approach. The Company’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 Eddystone Rail. Aux Sable During the year ended December 31, 2016, Aux Sable recorded an asset impairment charge of $37 million related to certain underutilized assets at Aux Sable US’ NGL extraction and fractionation plant. Eolien Maritime France SAS Effective May 19, 2016, Enbridge acquired a 50% interest in Eolien Maritime France SAS (EMF), a French offshore wind development company. EMF is co-owned by Enbridge and EDF Energies Nouvelles, a subsidiary of Électricité de France S.A. EMF holds licenses for three large-scale offshore wind farms off the coast of France, which are currently under development. Enbridge’s portion of the costs incurred to date is approximately $194 million (€136 million) with $58 million presented in Long-term investments, and $136 million presented in Deferred amounts and other assets. 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 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. 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. 13-kilometres (8-miles) off the UK Sussex coast at its nearest point. As at December 31, 2016, the Company had restricted long-term The Company’s total investment in the project through construction investments held in trust, invested in Canadian Treasury bonds, and is expected to be approximately $750 million (£370 million). are classiﬁed as held for sale and carried at fair value of $90 million The Rampion project was developed and is being constructed by (2015 – $49 million). As at December 31, 2016, the Company had E.ON Climate & Renewables UK Limited, a subsidiary of E.ON SE estimated future abandonment costs of $97 million (2015 – $48 million) (E.ON). Construction of the wind farm began in September 2015 related to LMCI. 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 $345 million (£195 million) presented in Long-term investments. 140 Enbridge Inc. 2016 Annual Report 13. Deferred Amounts and Other Assets December 31, (millions of Canadian dollars) Regulatory assets Long-term portion of derivative assets (Note 24) Affiliate long-term notes receivable Contractual receivables Deferred ﬁnancing costs Other As at December 31, 2016, deferred amounts of $150 million (2015 – $141 million) were subject to amortization and are presented net of accumulated amortization of $94 million (2015 – $80 million). Amortization expense for the year ended December 31, 2016 was $20 million (2015 – $18 million; 2016 2015 1,921 1,661 151 270 441 51 279 373 152 432 52 490 3,113 3,160 2014 – $22 million). 14. Intangible Assets December 31, 2016 (millions of Canadian dollars) Software Natural gas supply opportunities Power purchase agreements Customer relationships Land leases, permits and other December 31, 2015 (millions of Canadian dollars) Software Natural gas supply opportunities Power purchase agreements Land leases, permits and other Weighted Average Amortization Rate Cost Accumulated Amortization 11.8% 3.2% 3.2% 3.0% 4.8% 1,388 435 100 251 213 2,387 607 127 14 4 62 814 Weighted Average Amortization Rate Cost Accumulated Amortization 11.6% 4.0% 3.8% 4.2% 1,295 484 94 163 2,036 516 122 11 39 688 Net 781 308 86 247 151 1,573 Net 779 362 83 124 1,348 Total amortization expense for intangible assets was $177 million (2015 – $158 million; 2014 – $106 million) for the year ended December 31, 2016. The Company expects amortization expense for intangible assets for the years ending December 31, 2017 through 2021 of $198 million, $178 million, $159 million, $143 million and $129 million, respectively. 15. Goodwill (millions of Canadian dollars) Balance at January 1, 2015 Foreign exchange and other Impairment Balance at December 31, 2015 Foreign exchange and other Balance at December 31, 2016 Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other Consolidated 55 5 – 60 (1) 59 – – – – – – 428 30 (440) 18 (1) 17 – – – – – – – 2 – 2 – 2 – – – – – – 483 37 (440) 80 (2) 78 Notes to the Consolidated Financial Statements 141 Impairment The Company did not recognize any goodwill impairment for the year ended December 31, 2016. Gas Pipelines And Processing 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. 16. Accounts Payable and Other December 31, (millions of Canadian dollars) Operating accrued liabilities Trade payables Construction payables Current derivative liabilities (Note 24) Contractor holdbacks Taxes payable Security deposits Deferred revenue Asset retirement obligations (Note 19) Other 2016 2015 3,487 328 587 1,941 125 321 52 138 2 314 7,295 3,028 561 750 1,945 299 376 62 89 9 232 7,351 142 Enbridge Inc. 2016 Annual Report 17. Debt December 31, (millions of Canadian dollars) Enbridge Inc. United States dollar term notes1 Medium-term notes Fixed-to-ﬂoating subordinated term notes2 Commercial paper and credit facility draws3 Other4 Enbridge (U.S.) Inc. Medium-term notes5 Commercial paper and credit facility draws6 Enbridge Energy Partners, L.P. Senior notes7 Junior subordinated notes8 Commercial paper and credit facility draws9 Enbridge Gas Distribution Inc. Medium-term notes Debentures Commercial paper and credit facility draws Enbridge Income Fund Medium-term notes Commercial paper and credit facility draws Enbridge Pipelines (Southern Lights) L.L.C. Medium-term notes10 Enbridge Pipelines Inc. Medium-term notes11 Debentures Commercial paper and credit facility draws Other Enbridge Southern Lights LP Medium-term notes Midcoast Energy Partners, L.P. Senior notes12 Commercial paper and credit facility draws13 Other14 Total debt Current maturities Short-term borrowings15 Long-term debt Weighted Average Interest Rate Maturity 2016 2015 4.1% 4.2% 6.0% 2017 – 2046 2017 – 2064 2077 5.1% 2020 6.2% 8.1% 2018 – 2045 2067 4.4% 9.9% 2017 – 2050 2024 4.2% 2017 – 2044 5,639 4,998 1,007 4,672 4 14 126 6,781 537 2,226 3,904 85 351 2,075 225 4,221 5,698 – 5,667 7 14 1,665 7,404 554 1,988 3,603 85 599 2,405 – 2040 1,342 1,425 4.0% 4.5% 8.2% 2018 – 2046 2024 4.0% 2040 4.1% 2019 – 2024 4,525 200 1,032 4 323 537 564 (226) 40,945 (4,100) (351) 36,494 3,725 200 1,346 4 336 554 678 (198) 41,980 (1,990) (599) 39,391 1 2016 – US$4,200 million (2015 – US$3,050 million). 2 2016 – US$750 million (2015 – nil). 3 2016 – $3,600 million and US$799 million (2015 – $4,168 million and US$1,084 million). 4 Primarily capital lease obligations. 5 2016 – US$10 million (2015 – US$10 million). 6 2016 – US$94 million (2015 – US$1,203 million). 7 2016 – US$5,050 million (2015 – US$5,350 million). 8 2016 – US$400 million (2015 – US$400 million). 9 2016 – US$1,658 million (2015 – US$1,436 million). 10 2016 – US$1,000 million (2015 – US$1,030 million). 11 Included in medium-term notes is $100 million with a maturity date of 2112. 12 2016 – US$400 million (2015 – US$400 million). 13 2016 – US$420 million (2015 – US$490 million). 14 Primarily debt discount and debt issue costs. 15 Weighted average interest rate – 0.8% (2015 – 0.8%). For the years ending December 31, 2017 through 2021, debenture, term note and non-revolving credit facility maturities are $4,100 million, $1,172 million, $3,111 million, $2,797 million, $1,917 million respectively, and $21,618 million thereafter. The Company’s debentures and term notes bear interest at ﬁxed rates and interest obligations for the years ending December 31, 2017 through 2021 are $1,776 million, $1,645 million, $1,455 million, $1,259 million and $1,135 million, respectively. At December 31, 2016 and 2015, all debt was unsecured. Notes to the Consolidated Financial Statements 143 Interest Expense Year ended December 31, (millions of Canadian dollars) Debentures and term notes Commercial paper and credit facility draws Southern Lights project ﬁnancing Capitalized Interest Expense Year ended December 31, (millions of Canadian dollars) Enbridge Inc. Enbridge (U.S.) Inc. Enbridge Energy Partners, L.P. Enbridge Gas Distribution Inc. Enbridge Income Fund Enbridge Pipelines (Southern Lights) L.L.C. Enbridge Pipelines Inc. Enbridge Southern Lights LP Midcoast Energy Partners, L.P. Capitalized Credit Facilities 2016 2015 2014 1,714 197 – (321) 1,590 1,805 172 – (353) 1,624 1,425 71 49 (416) 1,129 2016 2015 2014 571 43 609 193 119 56 262 14 44 970 54 369 175 106 45 210 14 34 598 19 458 154 76 36 171 14 19 (321) 1,590 (353) 1,624 (416) 1,129 The following table provides details of the Company’s committed credit facilities at December 31, 2016 and December 31, 2015. December 31, (millions of Canadian dollars) Enbridge Inc. Enbridge (U.S.) Inc. Enbridge Energy Partners, L.P. Enbridge Gas Distribution Inc. Enbridge Income Fund Enbridge Pipelines (Southern Lights) L.L.C. Enbridge Pipelines Inc. Enbridge Southern Lights LP Midcoast Energy Partners, L.P. Total committed credit facilities Maturity Total Facilities Draws1 Available Total Facilities 2016 2015 2017 – 2020 2018 – 2019 2018 – 2020 2018 – 2019 2019 2018 2018 2018 2018 8,183 3,934 3,525 1,017 1,500 27 3,000 5 900 22,091 4,700 126 2,293 360 236 – 1,032 – 564 9,311 3,483 3,808 1,232 657 1,264 27 1,968 5 336 12,780 6,988 4,470 3,598 1,010 1,500 28 3,000 5 1,121 21,720 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. In addition to the committed credit facilities noted above, the Company also has $335 million (2015 – $349 million) of uncommitted demand credit facilities, of which $177 million (2015 – $185 million) were 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. As at December 31, 2016, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $7,344 million (2015 – $11,344 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, 2016, the Company was in compliance with all debt covenants. 144 Enbridge Inc. 2016 Annual Report 18. Other Long-Term Liabilities December 31, (millions of Canadian dollars) Regulatory liabilities Derivative liabilities (Note 24) Pension and OPEB liabilities (Note 26) Asset retirement obligations (Note 19) Environmental liabilities Other 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 11.0% (2015 – 1.7% to 9.4%). A reconciliation of movements in the Company’s ARO is as follows: December 31, (millions of Canadian dollars) Obligations at beginning of year Liabilities incurred Liabilities settled Change in estimate Foreign currency translation adjustment Accretion expense Obligations at end of year Presented as follows: Accounts payable and other (Note 16) Other long-term liabilities (Note 18) 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, (millions of Canadian dollars) Enbridge Energy Partners, L.P. Enbridge Energy Management, L.L.C. (EEM) Enbridge Gas Distribution Inc. preferred shares Renewable energy assets Other 2016 2015 793 2,713 597 230 76 572 787 3,950 517 189 89 524 4,981 6,056 2016 2015 198 2 (33) 63 (5) 7 232 2 230 232 185 2 (45) 30 21 5 198 9 189 198 2016 2015 (99) 36 100 516 24 577 412 203 100 561 24 1,300 Notes to the Consolidated Financial Statements 145 Enbridge Energy Partners, L.P. Noncontrolling interests in EEP represented the 80.2% (2015 – 80.0%) 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 primarily due to EEP distributing $670 million (2015 – $630 million; 2014 – $504 million) to its noncontrolling interest holders in line with EEP’s objective to make quarterly distributions from its available cash, as deﬁned in its partnership agreement and as approved by EEP’s Board of Directors. This decrease was partially offset by comprehensive income attributable to noncontrolling interests in EEP during the year. For the year ended December 31, 2016, EEP reported a net loss, as well as distributions to partners in excess of earnings attributable to partners, which reduced the carrying value of EEP’s Class A and Class B common units and i-units into deﬁcit positions. The EEP partnership agreement does not permit capital account deﬁcits in the capital account of any limited partner and thus requires that such capital account deﬁcits be brought to zero by additional allocations from other limited partner capital balances, to the extent such capital account balances are positive, and the General Partner on a pro-rata basis. As a result, Earnings attributable to noncontrolling interests and redeemable noncontrolling interests in the Consolidated Statements of Earnings for the year ended December 31, 2016 were higher by $816 million due to this reallocation (2015 – lower by $13 million). 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, 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 public common unit issuance. The Company participated only to the extent to maintain its 2% General Partner (GP) interest. The common unit issuance resulted in contributions of $366 million (US$289 million) from noncontrolling interest holders. Effective July 1, 2014, EECI, 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 decreased 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. 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% (2015 – 88.3%) of the listed shares of EEM not held by the Company. During the year ended December 31, 2016, the decrease in the carrying value of Noncontrolling interests in EEM is due to a comprehensive loss attributable to noncontrolling interests in EEM. 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, 2016, no preferred shares have been redeemed. Renewable Energy Assets Renewable energy assets include the VIEs (Note 10) of Magic Valley, Wildcat, Keechi and New Creek wind farms. During the year ended December 31, 2016, the net decrease in the carrying value of Noncontrolling interests in Renewable energy assets was primarily due to a comprehensive loss attributable to noncontrolling interests, which were partially offset by contributions, net of distributions, received from noncontrolling interests. 146 Enbridge Inc. 2016 Annual Report Redeemable Noncontrolling Interests Year ended December 31, (millions of Canadian dollars) Balance at beginning of year Earnings/(loss) Other comprehensive income/(loss), net of tax Change in unrealized gains/(loss) on cash ﬂow hedges Other comprehensive loss from equity investees Reclassiﬁcation to earnings of realized cash ﬂow hedges Reclassiﬁcation to earnings of unrealized cash ﬂow hedges Change in foreign currency translation adjustment Other comprehensive income/(loss) Distributions to unitholders Contributions from unitholders Reversal of cumulative redemption value adjustment attributable to ECT preferred units Dilution loss on Enbridge Income Fund issuance of trust units Dilution loss on Enbridge Income Fund equity investment Dilution gain/(loss) on Enbridge Income Fund indirect equity investment Redemption value adjustment Balance at end of year 2016 2015 2014 2,141 268 (17) – 3 6 (3) (11) (202) 591 – (4) (73) (4) 686 3,392 2,249 (3) (7) (12) 2 2 18 3 (114) 670 (541) (355) (132) 5 359 2,141 1,053 (11) (15) – – – 5 (10) (79) 323 – – – – 973 2,249 Redeemable noncontrolling interests in the Fund as at December 31, 2016 represented 45.6% (2015 – 40.7%, 2014 – 70.6%) of interests in the Fund’s trust units that are held by third parties. In April 2016, ENF completed a public equity offering of common shares for gross proceeds of $575 million and issued additional shares to Enbridge for gross proceeds of $143 million in order for Enbridge to maintain its 19.9% ownership interest in ENF. ENF used the proceeds from the common share issuances 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 40.7% to 45.6%. This resulted in contributions of $591 million, net of share issue costs, from redeemable noncontrolling interest holders and a dilution loss for redeemable noncontrolling interests of $4 million. In April 2016, the Fund used the aggregate proceeds of $718 million from the issuance of trust units to ENF to purchase additional common units of ECT, and ECT used the aggregate proceeds of $718 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 the Fund’s equity investment in ECT and a dilution loss for redeemable noncontrolling interests of $73 million for the year ended December 31, 2016. 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. 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, issued Special Interest Rights to Enbridge which are entitled to Temporary Performance Distribution Rights (TPDR) distributions. TPDR distributions occur when the Fund distribution rate exceeds a payout target and are paid in the form of Class D units. 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 resulted in a dilution gain for the Fund’s indirect equity investment in EIPLP. For the year ended December 31, 2016, a dilution loss for redeemable noncontrolling interests of $4 million was recorded (2015 – dilution gain of $5 million). Notes to the Consolidated Financial Statements 147 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 the United States portion of Alliance Pipeline 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 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. Distributions to noncontrolling unitholders were made on a monthly basis for the years ended December 31, 2016, 2015, and 2014 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 December 31, (millions of Canadian dollars; number of common shares in millions) Balance at beginning of year Common shares issued1 Dividend Reinvestment and Share Purchase Plan (DRIP) Shares issued on exercise of stock options Balance at end of year 2016 2015 2014 Number of Shares Amount Number of Shares Amount Number of Shares Amount 868 56 16 3 7,391 2,241 795 65 943 10,492 852 – 12 4 868 6,669 – 646 76 7,391 831 5,744 9 9 3 446 428 51 852 6,669 1 Gross proceeds – $2,300 million (2015 – nil; 2014 – $460 million); net issuance costs – $59 million (2015 – nil; 2014 – $14 million). 148 Enbridge Inc. 2016 Annual Report Preference Shares December 31, (millions of Canadian dollars; number of preference shares in millions) 2016 2015 2014 Number of Shares Amount Number of Shares Amount Number of Shares Amount Preference Shares, Series A Preference Shares, Series B Preference Shares, Series D Preference Shares, Series F Preference Shares, Series H Preference Shares, Series J Preference Shares, Series L Preference Shares, Series N Preference Shares, Series P Preference Shares, Series R Preference Shares, Series 1 Preference Shares, Series 3 Preference Shares, Series 5 Preference Shares, Series 7 Preference Shares, Series 9 Preference Shares, Series 11 Preference Shares, Series 13 Preference Shares, Series 15 Preference Shares, Series 17 Issuance costs Balance at end of year 5 20 18 20 14 8 16 18 16 16 16 24 8 10 11 20 14 11 30 125 500 450 500 350 199 411 450 400 400 411 600 206 250 275 500 350 275 750 5 20 18 20 14 8 16 18 16 16 16 24 8 10 11 20 14 11 – 125 500 450 500 350 199 411 450 400 400 411 600 206 250 275 500 350 275 – 5 20 18 20 14 8 16 18 16 16 16 24 8 10 11 20 14 11 – 125 500 450 500 350 199 411 450 400 400 411 600 206 250 275 500 350 275 – (147) 7,255 (137) 6,515 (137) 6,515 Notes to the Consolidated Financial Statements 149 Characteristics of the preference shares are as follows: (Canadian dollars unless otherwise stated) Preference Shares, Series A Preference Shares, Series B Preference Shares, Series D Preference Shares, Series F Preference Shares, Series H Preference Shares, Series J Preference Shares, Series L Preference Shares, Series N Preference Shares, Series P Preference Shares, Series R Preference Shares, Series 1 Preference Shares, Series 3 Preference Shares, Series 5 Preference Shares, Series 7 Preference Shares, Series 9 Preference Shares, Series 11 Preference Shares, Series 13 Preference Shares, Series 15 Preference Shares, Series 17 Initial Yield Dividend1 Per Share Base Redemption Value2 Redemption and Conversion Right to Convert Option Date2,3 Into3,4 5.50% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.00% 4.40% 4.40% 4.40% 4.40% 4.40% 4.40% 5.15% $1.375 $1.000 $1.000 $1.000 $1.000 US$1.000 US$1.000 $1.000 $1.000 $1.000 US$1.000 $1.000 US$1.100 $1.100 $1.100 $1.100 $1.100 $1.100 $1.288 $25 $25 $25 $25 $25 US$25 US$25 $25 $25 $25 US$25 – June 1, 2017 March 1, 2018 June 1, 2018 September 1, 2018 June 1, 2017 September 1, 2017 December 1, 2018 March 1, 2019 June 1, 2019 June 1, 2018 $25 September 1, 2019 US$25 $25 $25 $25 $25 $25 $25 March 1, 2019 March 1, 2019 December 1, 2019 March 1, 2020 June 1, 2020 September 1, 2020 March 1, 2022 – Series C Series E Series G Series I Series K Series M Series O Series Q Series S Series 2 Series 4 Series 6 Series 8 Series 10 Series 12 Series 14 Series 16 Series 18 1 The holder is entitled to receive a ﬁxed, cumulative, quarterly preferential dividend, as declared by the Board. With the exception of Series A Preference Shares, such ﬁxed dividend rate resets every ﬁve years beginning on the initial redemption and conversion option date. The Series 17 Preference Shares contain a feature where the ﬁxed dividend rate, when reset every ﬁve years, will not be less than 5.15%. No other series of Preference Shares has this feature. 2 Preference Shares, Series A may be redeemed any time at the Company’s option. For all other series of Preference Shares, the Company, may at its option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every ﬁfth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a speciﬁed series on a one-for-one basis on the Conversion Option Date and every ﬁfth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. 4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly ﬂoating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90 day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18); or US$25 x (number of days in quarter/365) x (three month United States Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6)). 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 13 million (2015 – 12 million; 2014 – 12 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, (number of common shares in millions) Weighted average shares outstanding Effect of dilutive options Diluted weighted average shares outstanding 2016 2015 2014 911 7 918 847 – 847 829 11 840 For the year ended December 31, 2016, 10,803,672 anti-dilutive stock options (2015 – 36,005,043; 2014 – 6,058,580) with a weighted average exercise price of $52.92 (2015 – $40.26; 2014 – $48.78) were excluded from the diluted earnings per common share calculation. 150 Enbridge Inc. 2016 Annual Report 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. 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 14 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. December 31, 2016 (options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year Options granted Options exercised1 Options cancelled or expired Options outstanding at end of year Options vested at end of year2 Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value 40.31 44.05 29.73 49.26 42.51 37.11 6.3 4.9 335 286 Number 32,788 6,373 (5,364) (888) 32,909 18,355 1 The total intrinsic value of ISO exercised during the year ended December 31, 2016 was $123 million (2015 – $126 million; 2014 – $117 million) and cash received on exercise was $37 million (2015 – $43 million; 2014 – $37 million). 2 The total fair value of options vested under the ISO Plan during the year ended December 31, 2016 was $36 million (2015 – $34 million; 2014 – $26 million). Notes to the Consolidated Financial Statements 151 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, Fair value per option (Canadian dollars)1 Valuation assumptions Expected option term (years)2 Expected volatility3 Expected dividend yield4 Risk-free interest rate5 2016 7.37 5 25.1% 4.4% 0.8% 2015 6.48 5 19.9% 3.2% 0.9% 2014 5.53 5 16.9% 2.9% 1.6% 1 Options granted to United States employees are based on New York Stock Exchange prices. The option value and assumptions shown are based on a weighted average of the United States and the Canadian options. The fair values per option were $7.01 (2015 – $6.22; 2014 – $5.45) for Canadian employees and US$6.60 (2015 – US$6.16; 2014 – US$5.35) for United States employees. 2 The expected option term is six years based on historical exercise practice and three years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields. Compensation expense recorded for the year ended December 31, 2016 for ISO was $43 million (2015 – $35 million; 2014 – $29 million). At December 31, 2016, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the ISO Plan was $50 million. The cost is expected to be fully recognized over a weighted average period of approximately two years. 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, 2016, 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, 2016, all performance targets have been met and the options are exercisable until August 15, 2020. December 31, 2016 (Options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year Options exercised1 Options outstanding at end of year Options vested at end of year2 Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value 39.75 41.29 39.57 39.34 3.2 3.2 38 32 Number 3,217 (335) 2,882 2,409 1 The total intrinsic value of PSO exercised during the year ended December 31, 2016 was $7 million (2015 – $43 million; 2014 – nil) and cash received on exercise was $3 million (2015 – $13 million; 2014 – nil). 2 The total fair value of options vested under the PSO Plan during the year ended December 31, 2016 was $2 million (2015 – $6 million; 2014 – $5 million). 152 Enbridge Inc. 2016 Annual Report 2014 5.77 6.5 15.0% 2.8% 1.7% Assumptions used to determine the fair value of PSO granted using the Bloomberg barrier option valuation model are as follows: Year ended December 31, Fair value per option (Canadian dollars) Valuation assumptions Expected option term (years)1 Expected volatility2 Expected dividend yield3 Risk-free interest rate4 1 The expected option term is based on historical exercise practice. 2 Expected volatility is determined with reference to historic daily share price volatility. 3 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 4 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields. Compensation expense recorded for the year ended December 31, 2016 for PSO was $3 million (2015 – $3 million; 2014 – $3 million). At December 31, 2016, unrecognized compensation cost related to non-vested stock-based compensation arrangements granted under the PSO Plan was $2 million. The cost is expected to be fully recognized over a weighted average period of approximately one year. 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 2016 expense, multipliers of two, were used for each of the 2014, 2015 and 2016 PSU grants. December 31, 2016 (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year Units granted Units cancelled Units matured1 Dividend reinvestment Units outstanding at end of year Weighted Average Remaining Contractual Life (Years) Aggregate Intrinsic Value 1.5 54 Number 536 294 (14) (295) 35 556 1 The total amount paid during the year ended December 31, 2016 for PSU was $22 million (2015 – $35 million; 2014 – $36 million). Compensation expense recorded for the year ended December 31, 2016 for PSU was $33 million (2015 – $12 million; 2014 – $40 million). As at December 31, 2016, unrecognized compensation expense related to non-vested units granted under the PSU Plan was $30 million and is expected to be fully recognized over a weighted average period of approximately two years. Notes to the Consolidated Financial Statements 153 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. December 31, 2016 (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year Units granted Units cancelled Units matured1 Dividend reinvestment Units outstanding at end of year Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value 1.4 105 Number 1,906 972 (154) (992) 122 1,854 1 The total amount paid during the year ended December 31, 2016 for RSU was $56 million (2015 – $45 million; 2014 – $45 million). Compensation expense recorded for the year ended December 31, 2016 for RSU was $51 million (2015 – $47 million; 2014 – $44 million). As at December 31, 2016, unrecognized compensation expense related to non-vested units granted under the RSU Plan was $62 million and is expected to be fully recognized over a weighted average period of approximately one year. 23. Components of Accumulated Other Comprehensive Income/(Loss) Changes in AOCI attributable to Enbridge common shareholders for the years ended December 31, 2016, 2015 and 2014, are as follows: Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Amortization Adjustment Total 1,632 (760) 147 (11) 1 (18) 21 (620) 102 (56) 46 (287) (45) – – – – 21 (24) 11 (4) 7 (304) 1,058 (millions of Canadian dollars) Balance at January 1, 2016 Other comprehensive income/(loss) retained in AOCI Other comprehensive (income)/loss reclassiﬁed to earnings Interest rate contracts1 Commodity contracts2 Foreign exchange contracts3 Other contracts4 Amortization of pension and OPEB actuarial loss prior service costs5 Tax impact Income tax on amounts retained in AOCI Income tax on amounts reclassiﬁed to earnings Balance at December 31, 2016 (688) (216) 147 (11) 1 (18) – (97) 91 (52) 39 (746) (795) 171 3,365 (665) – – – – – – – – – – 171 (665) (5) – (5) – – – (629) 2,700 37 (5) – – – – – (5) 5 – 5 37 154 Enbridge Inc. 2016 Annual Report Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Amortization Adjustment (millions of Canadian dollars) Balance at January 1, 2015 Other comprehensive income/(loss) retained in AOCI Other comprehensive (income)/loss reclassiﬁed to earnings Interest rate contracts1 Commodity contracts2 Foreign exchange contracts3 Other contracts4 Amortization of pension and OPEB actuarial loss and prior service costs5 Other comprehensive loss reclassiﬁed to earnings of derecognized cash ﬂow hedges Tax impact Income tax on amounts retained in AOCI Income tax on amounts reclassiﬁed to earnings Income tax on amounts reclassiﬁed to earnings of derecognized cash ﬂow hedges Balance at December 31, 2015 (488) 73 (34) (11) 7 26 – (338) (277) (29) 15 91 77 (688) 108 (952) 309 3,056 (5) 47 (359) 65 – – – – – – – – – – – – (952) 3,056 49 – – 49 (795) – – – – 3,365 – – – – – – 47 (5) – – (5) 37 – – – – 32 – 97 (14) (11) – (25) (287) (millions of Canadian dollars) Balance at January 1, 2014 Other comprehensive income/(loss) retained in AOCI Other comprehensive (income)/loss reclassiﬁed to earnings Interest rate contracts1 Commodity contracts2 Foreign exchange contracts3 Other contracts4 Amortization of pension and OPEB actuarial loss and prior service costs5 Tax impact Income tax on amounts retained in AOCI Income tax on amounts reclassiﬁed to earnings Balance at December 31, 2014 Cash Flow Net Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Amortization Adjustment (1) (857) 201 (2) 8 (23) – (673) 231 (45) 186 (488) 378 (301) (778) 1,087 – – – – – – – – – – (301) 1,087 31 – 31 108 – – – 309 (15) 10 – – – – – 10 – – – (5) (183) (265) – – – – 18 (247) 74 (3) 71 (359) Total (435) 2,289 (34) (11) 7 26 32 (338) 1,971 1 4 91 96 1,632 Total (599) (326) 201 (2) 8 (23) 18 (124) 336 (48) 288 (435) 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 income/(expense) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 These components are included in the computation of net periodic pension costs and are reported within Operating and administrative expense in the Consolidated Statements of Earnings. Notes to the Consolidated Financial Statements 155 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 via execution of ﬂoating to ﬁxed interest rate swaps with an average swap rate of 2.4%. The Company’s earnings and cash ﬂows are also exposed to variability in longer term interest rates ahead of anticipated ﬁxed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a program to signiﬁcantly mitigate its exposure to long-term interest rate variability on select forecast term debt issuances via execution of ﬂoating to ﬁxed interest rate swaps with an average swap rate of 3.7%. The Company also monitors its debt portfolio mix of ﬁxed and variable rate debt instruments to maintain a consolidated portfolio of debt within its Board of Directors approved policy limit of a maximum of 25% ﬂoating rate debt as a percentage of total debt outstanding. The Company primarily uses qualifying derivative instruments to manage interest rate risk. Commodity Price Risk The Company’s earnings and cash ﬂows are exposed to changes in commodity prices as a result of its ownership interests in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. The Company employs ﬁnancial derivative instruments to ﬁx a portion of the variable price exposures that arise from physical transactions involving these commodities. The Company uses primarily non-qualifying derivative instruments to manage commodity price risk. Equity Price Risk Equity price risk is the risk of earnings ﬂuctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, RSU. The Company uses a combination of qualifying and non-qualifying derivative instruments to manage equity price risk. 156 Enbridge Inc. 2016 Annual Report 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, 2016 or 2015. 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. December 31, 2016 (millions of Canadian dollars) Accounts receivable and other (Note 7) Foreign exchange contracts Interest rate contracts Commodity contracts Deferred amounts and other assets (Note 13) Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Accounts payable and other (Note 16) Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Other long-term liabilities (Note 18) Foreign exchange contracts Interest rate contracts Commodity contracts Total net derivative asset/(liability) Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Non–Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments 101 3 9 113 1 8 7 1 17 – (452) – (1) (453) – (268) – (268) 102 (709) 16 – (591) 3 – – 3 3 – – – 3 (268) – – – 5 – 232 237 69 – 61 1 131 (727) (131) (359) (3) 109 3 241 353 73 8 68 2 151 (995) (583) (359) (4) (268) (1,220) (1,941) (68) – – (68) (1,961) (205) (211) (2,377) (330) (2,614) – – – (336) (277) (2) (330) (3,229) (2,029) (473) (211) (2,713) (2,842) (1,045) (261) (2) (4,150) (103) (3) (125) (231) (72) (6) (22) – (100) 103 3 125 – 231 72 6 22 100 – – – – – 6 – 116 122 1 2 46 2 51 (892) (580) (234) (4) (1,710) (1,957) (467) (189) (2,613) (2,842) (1,045) (261) (2) (4,150) Notes to the Consolidated Financial Statements 157 December 31, 2015 (millions of Canadian dollars) Accounts receivable and other (Note 7) Foreign exchange contracts Interest rate contracts Commodity contracts Deferred amounts and other assets (Note 13) Foreign exchange contracts Interest rate contracts Commodity contracts Accounts payable and other (Note 16) Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Other long-term liabilities (Note 18) Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Total net derivative asset/(liability) Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Non– Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments 6 2 7 15 114 18 7 139 (1) (379) – (2) (382) – (405) – (8) (413) 119 (764) 14 (10) (641) 2 – – 2 4 – – 4 (106) – – – 2 – 772 774 10 – 220 230 (765) (185) (501) (6) 10 2 779 791 128 18 227 373 (872) (564) (501) (8) (106) (1,457) (1,945) (252) (2,796) (3,048) – – – (224) (260) (5) (629) (260) (13) (252) (3,285) (3,950) (352) (3,549) – – – (409) 231 (11) (3,782) (1,173) 245 (21) (352) (3,738) (4,731) (3) (2) (211) (216) (127) (14) (77) (218) 3 2 194 – 199 127 14 77 – 218 – – (17)1 – (17) 7 – 568 575 1 4 150 155 (869) (562) (307) (8) (1,746) (2,921) (615) (183) (13) (3,732) (3,782) (1,173) 228 (21) (4,748) 1 Amount available for offset includes $17 million of cash collateral. 158 Enbridge Inc. 2016 Annual Report The following table summarizes the maturity and notional principal or quantity outstanding related to the Company’s derivative instruments. December 31, 2016 2017 2018 2019 2020 2021 Thereafter Foreign exchange contracts – United States dollar forwards – purchase (millions of United States dollars) 991 2 2 2 2,768 2,943 2,722 Foreign exchange contracts – United States dollar forwards – sell (millions of United States dollars) Foreign exchange contracts – GBP forwards – purchase (millions of GBP) Foreign exchange contracts – GBP forwards – sell (millions of GBP) Foreign exchange contracts – Japanese yen forwards – purchase (millions of yen) 4,369 91 – – 6 – – Interest rate contracts – short-term borrowings (millions of Canadian dollars) Interest rate contracts – long-term debt (millions of Canadian dollars) 6,713 3,998 5,161 2,743 Equity contracts (millions of Canadian dollars) Commodity contracts – natural gas (billions of cubic feet) Commodity contracts – crude oil (millions of barrels) Commodity contracts – NGL (millions of barrels) Commodity contracts – power (megawatt hours (MWH)) 48 (93) (11) (8) 40 40 (42) (9) (6) 30 – 89 32,662 1,581 768 – (17) – – 31 – 25 – 153 – – (9) – – 35 – 566 – 27 – 100 – – – – – – 223 – 144 – 300 – – – – – (3) (43) December 31, 2015 2016 2017 2018 2019 2020 Thereafter Foreign exchange contracts – United States dollar forwards – purchase (millions of United States dollars) 172 413 2 2 2 Foreign exchange contracts – United States dollar forwards – sell (millions of United States dollars) Foreign exchange contracts – GBP forwards – purchase (millions of GBP) Foreign exchange contracts – GBP forwards – sell (millions of GBP) Interest rate contracts – short-term borrowings (millions of Canadian dollars) Interest rate contracts – long-term debt (millions of Canadian dollars) Equity contracts (millions of Canadian dollars) Commodity contracts – natural gas (billions of cubic feet) Commodity contracts – crude oil (millions of barrels) Commodity contracts – NGL (millions of barrels) Commodity contracts – power (megawatt hours) 3,059 3,213 3,133 2,630 2,303 70 – 8,382 4,291 51 (126) (6) (5) 40 77 – 7,604 3,371 48 (209) (17) 1 40 6 – 4,536 1,960 – (17) (9) – 30 – 89 1,574 773 – 2 – – 31 – 25 156 – – 1 – – 35 (35) – 787 – 144 406 – – – – – Notes to the Consolidated Financial Statements 159 The Effect of Derivative Instruments on the Consolidated Statements of Earnings and Comprehensive Income The following table presents the effect of cash ﬂow hedges and net investment hedges on the Company’s consolidated earnings and consolidated comprehensive income, before the effect of income taxes. Year ended December 31, (millions of Canadian dollars) Amount of unrealized gains/(loss) recognized in OCI Cash ﬂow hedges Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Net investment hedges Foreign exchange contracts Amount of (gains)/loss reclassiﬁed from AOCI to earnings (effective portion) Foreign exchange contracts1 Interest rate contracts2 Commodity contracts3 Other contracts4 De-designation of qualifying hedges in connection with the Canadian Restructuring Plan Interest rate contracts 2 Amount of (gains)/loss reclassiﬁed from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts2 Commodity contracts3 2016 2015 2014 (19) (90) 14 39 22 (34) 2 145 (12) (29) 106 – – 61 – 61 77 (275) 9 (47) (248) (484) 9 128 (46) 28 119 338 338 21 5 26 8 (1,086) 50 13 (113) (1,128) 8 101 4 (7) 106 – – 216 (6) 210 1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 Reported within Transportation and other services revenues, Commodity 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. The Company estimates that a gain of $23 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 36 months as at December 31, 2016. 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, (millions of Canadian dollars) Foreign exchange contracts1 Interest rate contracts2 Commodity contracts3 Other contracts4 Total unrealized derivative fair value gain/(loss), net 2016 2015 2014 935 73 (508) 9 509 (2,187) (363) 199 (22) (2,373) (936) 4 1,031 7 106 1 Reported within Transportation and other services revenues (2016 – $497 million gain; 2015 – $1,383 million loss; 2014 – $496 million loss) and Other income/(expense) (2016 – $438 million gain; 2015 – $804 million loss; 2014 – $440 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 (2016 – $52 million loss; 2015 – $328 million gain; 2014 – $741 million gain), Commodity sales (2016 – $474 million loss; 2015 – $226 million loss; 2014 – nil), Commodity costs (2016 – $38 million gain; 2015 – $99 million gain; 2014 – $303 million gain) and Operating and administrative expense (2016 – $20 million loss; 2015 – $2 million loss; 2014 – $13 million loss) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 160 Enbridge Inc. 2016 Annual Report 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 mitigate this risk, the Company forecasts cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintains substantial capacity under its committed bank lines of credit to address any contingencies. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. The Company also maintains current shelf prospectuses with securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. 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, 2016. As a result, all credit facilities are available to the Company and the banks are obligated to fund and have been funding the Company under the terms of the facilities. 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, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools. The Company had group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, (millions of Canadian dollars) Canadian ﬁnancial institutions United States ﬁnancial institutions European ﬁnancial institutions Asian ﬁnancial institutions Other1 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at December 31, 2016, the Company had provided letters of credit totalling $160 million in lieu of providing cash collateral to its counterparties pursuant to the terms of the relevant ISDA agreements. The Company held no cash collateral on derivative asset exposures at December 31, 2016 and $17 million of cash collateral at December 31, 2015. 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 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. 2016 2015 39 179 106 1 162 487 47 450 95 4 213 809 Notes to the Consolidated Financial Statements 161 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 classiﬁed in Levels 2 and 3, the Company uses standard valuation techniques to calculate the estimated fair value. These methods include discounted cash ﬂows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, the Company uses observable market prices (interest, foreign exchange, commodity and share 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. 162 Enbridge Inc. 2016 Annual Report Fair Value of Derivatives The Company has categorized its derivative assets and liabilities measured at fair value as follows: December 31, 2016 (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts Interest rate contracts Commodity contracts Long-term derivative assets Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Financial liabilities Current derivative liabilities Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Long-term derivative liabilities Foreign exchange contracts Interest rate contracts Commodity contracts Total net ﬁnancial asset/(liability) Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Level 1 Level 2 Level 3 Total Gross Derivative Instruments – – 2 2 – – – – – – – (12) – (12) – – – – – – (10) – (10) 109 3 86 198 73 8 43 2 126 (995) (583) (75) (4) (1,657) (2,029) (473) (10) (2,512) (2,842) (1,045) 44 (2) (3,845) – – 153 153 – – 25 – 25 – – (272) – (272) – – (201) (201) – – (295) – (295) 109 3 241 353 73 8 68 2 151 (995) (583) (359) (4) (1,941) (2,029) (473) (211) (2,713) (2,842) (1,045) (261) (2) (4,150) Notes to the Consolidated Financial Statements 163 December 31, 2015 (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts Interest rate contracts Commodity contracts Long-term derivative assets Foreign exchange contracts Interest rate contracts Commodity contracts Financial liabilities Current derivative liabilities Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Long-term derivative liabilities Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Total net ﬁnancial asset/(liability) Foreign exchange contracts Interest rate contracts Commodity contracts Other contracts Level 1 Level 2 Level 3 Total Gross Derivative Instruments – – 14 14 – – – – – – (3) – (3) – – – – – – – 11 – 11 10 2 210 222 128 18 121 267 (872) (564) (130) (8) (1,574) (3,048) (629) (21) (13) (3,711) (3,782) (1,173) 180 (21) (4,796) – – 555 555 – – 106 106 – – (368) – (368) – – (239) – (239) – – 54 – 54 10 2 779 791 128 18 227 373 (872) (564) (501) (8) (1,945) (3,048) (629) (260) (13) (3,950) (3,782) (1,173) 245 (21) (4,731) The signiﬁcant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2016 (fair value in millions of Canadian dollars) Commodity contracts – ﬁnancial1 Natural gas NGL Power Commodity contracts – physical1 Natural gas Crude NGL Commodity options2 Crude NGL Power Fair Value Unobservable Input Minimum Price/Volatility Maximum Price/Volatility Weighted Average Price/Volatility Unit of Measurement 30 1 Forward gas price Forward NGL price (159) Forward power price (72) (91) 4 4 (13) 1 (295) Forward gas price Forward crude price Forward NGL price Option volatility Option volatility Option volatility 3.65 0.37 26.00 2.10 40.97 0.37 22% 32% 22% 5.62 1.66 78.70 11.05 78.94 1.75 33% 103% 51% 4.77 1.14 48.32 4.24 68.58 1.06 25% 57% 23% $/mmbtu3 $/gallon $/MWH $/mmbtu3 $/barrel $/gallon 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). 164 Enbridge Inc. 2016 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 classiﬁed as Level 3 in the fair value hierarchy were as follows: Year ended December 31, (millions of Canadian dollars) Level 3 net derivative asset at beginning of period Total loss Included in earnings1 Included in OCI Settlements Level 3 net derivative liability at end of period 2016 2015 54 149 (113) 3 (239) (295) 136 (1) (230) 54 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, 2016 or 2015. 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 $110 million as at December 31, 2016 (2015 – $126 million). The Company has a held to maturity preferred share investment carried at its amortized cost of $355 million as at December 31, 2016 (2015 – $359 million). These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%. As at December 31, 2016, the fair value of this preferred share investment approximates its face value of $580 million (2015 – $580 million). As at December 31, 2016, the Company’s long-term debt had a carrying value of $40,761 million (2015 – $41,530 million) before debt issuance cost and a fair value of $43,910 million (2015 – $41,045 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, 2016, the Company recognized an unrealized foreign exchange gain on the translation of United States dollar denominated debt of $121 million (2015 – unrealized loss of $631 million) and an unrealized gain on the change in fair value of its outstanding foreign exchange forward contracts of $21 million (2015 – unrealized loss of $250 million) in OCI. The Company recognized a realized gain of $3 million (2015 – realized gain of $4 million) in OCI associated with the settlement of foreign exchange forward contracts and also recognized a realized gain of $26 million (2015 – realized loss of $75 million) 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, 2016 (2015 – nil). Notes to the Consolidated Financial Statements 165 25. Income Taxes Income Tax Rate Reconciliation Year ended December 31, (millions of Canadian dollars) Earnings before income taxes and discontinued operations Canadian federal statutory income tax rate Expected federal taxes at statutory rate Increase/(decrease) resulting from: Provincial and state income taxes1 Foreign and other statutory rate differentials Effects of rate-regulated accounting2 Foreign allowable interest deductions Part VI.1 tax, net of federal Part I deduction Intercompany sale of investment3 Non-taxable portion of gain on sale of investment to unrelated party4 Valuation allowance5 Noncontrolling interests Other6 Income taxes on earnings before discontinued operations Effective income tax rate 2016 2015 2014 2,451 15% 368 34 (56) (116) (107) 56 6 (61) 22 (15) 11 142 5.8% 11 15% 2 (204) 310 (52) (84) 55 23 – 154 (28) (6) 170 2,173 15% 326 (36) 394 (97) (65) 47 68 – 2 (28) – 611 1,545.5% 28.1% 1 The change in provincial and state income taxes from 2015 to 2016 reﬂects the increase in earnings from the Canadian operations and the decrease in earnings from the United States operations. 2 The increase in 2016 is due to the federal component of the tax effect of the 2015 impairment of regulatory receivables. 3 In November 2016, September 2015 and November 2014, certain assets were sold 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. 4 The amount in 2016 represents the federal component of the non-taxable portion of the gain on the sale of the South Prairie Region assets to unrelated party. 5 The decrease from 2015 to 2016 is due to the federal component of the tax effect of a valuation allowance on the deferred tax assets related to an outside basis temporary difference that, in 2015, was no longer more likely than not to be realized. 6 2015 included $17 million recovery 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, (millions of Canadian dollars) Earnings/(loss) before income taxes and discontinued operations Canada United States Other Current income taxes Canada United States Other Deferred income taxes Canada United States Other Income taxes on earnings before discontinued operations 166 Enbridge Inc. 2016 Annual Report 2016 2015 2014 2,034 (333) 750 2,451 74 21 4 99 188 (151) 6 43 142 (1,365) 808 568 11 157 3 3 163 (558) 565 – 7 170 114 1,614 445 2,173 35 (15) 4 24 (193) 780 – 587 611 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, (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment Investments Regulatory assets Other Total deferred income tax liabilities Deferred income tax assets Financial instruments Pension and OPEB plans Loss carryforwards Other Total deferred income tax assets Less valuation allowance Total deferred income tax assets, net Net deferred income tax liabilities Presented as follows:1 Accounts receivable and other (Note 7) Deferred income taxes Total deferred income tax assets Accounts payable and other Deferred income taxes Total deferred income tax liabilities Net deferred income tax liabilities 2016 2015 (3,867) (2,938) (439) (47) (7,291) 1,215 219 1,189 374 2,997 (572) 2,425 (4,866) – 1,170 1,170 – (6,036) (6,036) (4,866) (3,423) (3,024) (354) (85) (6,886) 1,374 202 848 274 2,698 (538) 2,160 (4,726) 367 839 1,206 (17) (5,915) (5,932) (4,726) 1 Effective January 1, 2016, the Company elected to early adopt ASU 2015-17 (Note 3). A valuation allowance has 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, 2016, the Company recognized the beneﬁt of unused tax loss carryforwards of $2,486 million (2015 – $1,754 million) in Canada which start to expire in 2025 and beyond. As at December 31, 2016, the Company recognized the beneﬁt of unused tax loss carryforwards of $1,287 million (2015 – $899 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 $4.1 billion (2015 – $4.0 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 Canada (Federal, Alberta and Ontario). The Company’s 2008 to 2016 taxation years are still open for audit in the Canadian jurisdictions and the 2013 to 2016 taxation years remain open for audit in the United States jurisdictions. The Company is currently under examination for income tax matters in Canada for the 2013 and 2014 taxation years. The Company is not currently under examination for income tax matters in any other material jurisdiction where it is subject to income tax. Notes to the Consolidated Financial Statements 167 2016 2015 65 27 (2) (6) 84 51 5 9 – 65 Unrecognized Tax Beneﬁts Year ended December 31, (millions of Canadian dollars) Unrecognized tax beneﬁts at beginning of year Gross increases for tax positions of current year Change in translation of foreign currency Lapses of statute of limitations Unrecognized tax beneﬁts at end of year The unrecognized tax beneﬁts as at December 31, 2016, if recognized, would affect the Company’s effective income tax rate. The Company does not anticipate further adjustments to the unrecognized tax beneﬁts during the next 12 months that would have a material impact on its consolidated ﬁnancial statements. The Company recognizes accrued interest and penalties related to unrecognized tax beneﬁts as a component of Income taxes. Income taxes for the year ended December 31, 2016 included $1 million recovery (2015 – $2 million expense; 2014 – nil) of interest and penalties. As at December 31, 2016, interest and penalties of $6 million (2015 – $7 million) have been accrued. 26. Retirement and Postretirement Beneﬁts Pension Plans The Company has three registered pension plans which provide either deﬁned beneﬁt or deﬁned contribution pension beneﬁts, or both, to employees of the Company. The Canadian Plans provide Company funded deﬁned beneﬁt pension and/or deﬁned contribution beneﬁts to Canadian employees of Enbridge. The United States Plan provides Company funded deﬁned beneﬁt pension beneﬁts for United States based employees. The Company has four supplemental pension plans that provide pension beneﬁts in excess of the basic plans for certain employees. A measurement date of December 31, 2016 was used to determine the plan assets and accrued beneﬁt obligation for the Canadian and United States plans. Deﬁned Beneﬁt 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. Contributions by the Company are made in accordance with independent actuarial valuations and are invested primarily in publicly-traded equity and ﬁxed income securities. The effective dates of the most recent actuarial valuations and the next required actuarial valuations for the basic plans are as follows: Canadian Plans Liquids Pipelines Gas Distribution United States Plan Deﬁned Contribution Plans Effective Date of Most Recently Filed Actuarial Valuation Effective Date of Next Required Actuarial Valuation December 31, 2015 December 31, 2013 January 1, 2016 December 31, 2016 December 31, 2016 January 1, 2017 Contributions are generally based on the employee’s age, years of service and remuneration. For deﬁned contribution plans, beneﬁt costs equal amounts required to be contributed by the Company. Other Postretirement Beneﬁts OPEB primarily includes supplemental health and dental, health spending accounts and life insurance coverage for qualifying retired employees. 168 Enbridge Inc. 2016 Annual Report 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. December 31, (millions of Canadian dollars) Change in accrued beneﬁt obligation Beneﬁt obligation at beginning of year Service cost Interest cost Employees’ contributions Actuarial (gains)/loss Beneﬁts paid Effect of foreign exchange rate changes Other Beneﬁt obligation at end of year Change in plan assets Fair value of plan assets at beginning of year Actual return on plan assets Employer’s contributions Employees’ contributions Beneﬁts paid Effect of foreign exchange rate changes Other Fair value of plan assets at end of year1 Underfunded status at end of year Presented as follows: Deferred amounts and other assets Accounts payable and other Other long-term liabilities (Note 18) Pension OPEB 2016 2015 2016 2015 2,551 155 89 – 112 (108) (14) (7) 2,470 167 98 – (172) (90) 79 (1) 2,778 2,551 2,229 2,062 168 102 – (108) (10) (1) 2,380 (398) 5 – (403) (398) 88 116 – (90) 54 (1) 2,229 (322) 6 – (328) (322) 308 8 11 1 12 (12) (4) (12) 312 115 5 9 1 (12) (3) – 115 (197) 4 (7) (194) (197) 276 8 11 1 9 (12) 21 (6) 308 99 (2) 10 1 (12) 19 – 115 (193) 2 (6) (189) (193) 1 Assets of $44 million (2015 – $40 million) are held by the Company in trust accounts that back non-registered supplemental pension plans beneﬁtting United States plan participants. Due to United States tax regulations, these assets are not restricted from creditors, and therefore the Company is unable to include these balances in 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 status as at the end of the year. The weighted average assumptions made in the measurement of the projected beneﬁt obligations of the pension plans and OPEB are as follows: Year ended December 31, Discount rate Average rate of salary increases 2016 4.0% 3.6% Pension 2015 4.2% 3.6% 2014 4.0% 4.0% 2016 4.0% OPEB 2015 4.2% 2014 3.9% Notes to the Consolidated Financial Statements 169 Net Beneﬁt Costs Recognized Year ended December 31, (millions of Canadian dollars) Beneﬁts earned during the year Interest cost on projected beneﬁt obligations Expected return on plan assets Amortization of prior service credits Amortization of actuarial loss Net deﬁned beneﬁt costs on an accrual basis Deﬁned contribution beneﬁt costs Net beneﬁt cost recognized in Earnings Amount recognized in OCI: Net actuarial (gains)/loss1 Net prior service credit2 Total amount recognized in OCI Total amount recognized in Comprehensive income Pension OPEB 2016 2015 2014 2016 2015 2014 155 89 (148) – 35 131 3 134 24 – 24 158 167 98 (142) – 49 172 4 176 (107) – (107) 69 108 93 (123) – 28 106 4 110 232 – 232 342 8 11 (6) (1) 1 13 – 13 12 (12) – 13 8 11 (6) – 1 14 – 14 16 (6) 10 24 8 12 (5) – – 15 – 15 15 – 15 30 1 Unamortized actuarial losses included in AOCI, before tax, were $425 million (2015 – $404 million) relating to the pension plans and $54 million (2015 – $44 million) relating to OPEB at December 31, 2016. 2 Unamortized prior service credits included in AOCI, before tax, were $13 million (2015 – $1 million) relating to OPEB at December 31, 2016. The Company estimates that approximately $36 million related to pension plans and $1 million related to OPEB at December 31, 2016 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 reﬂect 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, 2016, an offsetting regulatory liability increased by $10 million (2015 – nil) and has been recorded to the extent pension and OPEB costs are expected to be refunded to customers in future rates. The weighted average assumptions made in the measurement of the cost of the pension plans and OPEB are as follows: Year ended December 31, Discount rate – service cost Discount rate – interest cost Average rate of return on plan assets Average rate of salary increases 2016 4.1% 4.1% 6.6% 3.6% Pension 2015 4.0% 4.0% 6.7% 4.0% 2014 5.0% 5.0% 6.7% 3.7% 2016 4.2% 4.2% 6.0% OPEB 2015 3.9% 3.9% 6.0% 2014 4.9% 4.9% 6.0% 170 Enbridge Inc. 2016 Annual Report Medical Cost Trends The assumed rates for the next year used to measure the expected cost of beneﬁts are as follows: Canadian Plans Drugs Other medical United States Plan Medical Cost Trend Rate Assumption for Next Fiscal Year Ultimate Medical Cost Trend Rate Assumption Year in which Ultimate Medical Cost Trend Rate Assumption is Achieved 6.6% 4.5% 6.9% 4.5% – 4.5% 2034 – 2037 A 1% increase in the assumed medical care trend rate would result in an increase of $23 million in the beneﬁt obligation and an increase of $1 million in service and interest costs. A 1% decrease in the assumed medical care trend rate would result in a decrease of $45 million in the beneﬁt obligation and a decrease of $2 million in service 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 ﬂow requirements of the plan; (iv) the operating environment and ﬁnancial situation of the Company and its ability to withstand ﬂuctuations 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 Year ended December 31, Canadian Plans United States Plan Target Mix for Plan Assets Equity securities Fixed income securities Other Pension 2016 6.6% 7.2% 2015 6.7% 7.2% OPEB 2016 6.0% 2015 6.0% Canadian Plans Liquids Pipelines Plan Gas Distribution Plan United States Plan 62.5% 30.0% 7.5% 53.5% 40.0% 6.5% 62.5% 30.0% 7.5% Notes to the Consolidated Financial Statements 171 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, 2016, the pension assets were invested 48.3% (2015 – 56.4%) in equity securities, 31.4% (2015 – 31.4%) in ﬁxed income securities and 20.3% (2015 – 12.2%) in other. The OPEB assets were invested 60.0% (2015 – 59.1%) in equity securities, 39.1% (2015 – 40.0%) in ﬁxed income securities and 0.9% (2015 – 0.9%) in other. The following table summarizes the Company’s pension ﬁnancial instruments at fair value. Non-ﬁnancial instruments with a carrying value of $7 million asset (2015 – $21 million asset) and refundable tax assets of $105 million (2015 – $106 million) have been excluded from the table below. December 31, (millions of Canadian dollars) Pension Cash and cash equivalents Fixed income securities Canadian government bonds Corporate bonds and debentures Canadian corporate bond index fund Canadian government bond index fund United States debt index fund Equity Canadian equity securities United States equity securities Global equity securities Canadian equity funds United States equity funds Global equity funds Infrastructure4 Real estate4 Forward currency contracts OPEB Cash and cash equivalents Fixed income securities United States government and government agency bonds Equity United States equity funds Global equity funds 2016 2015 Level 11 Level 22 Level 33 Total Level 11 Level 22 Level 33 Total 47 137 5 277 214 111 138 2 114 287 271 167 – – – 1 45 35 34 – – 3 – – – – – 30 – – 140 – – 4 – – – – – – – – – – – – – – – – 184 137 – – – – – 47 137 8 277 214 111 138 2 144 287 271 307 184 137 4 1 45 35 34 37 131 5 259 201 102 133 2 106 253 243 161 – – – 2 46 34 34 – – 3 – – – – – 25 – 5 148 – – (10) – – – – – – – – – – – – – – – – 182 115 – – – – – 37 131 8 259 201 102 133 2 131 253 248 309 182 115 (10) 2 46 34 34 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with signiﬁcant observable inputs. 3 Level 3 assets include assets with signiﬁcant unobservable inputs. 4 The fair values of the infrastructure and real estate investments are established through the use of valuation models. Changes in the net fair value of plan assets classiﬁed as Level 3 in the fair value hierarchy were as follows: December 31, (millions of Canadian dollars) Balance at beginning of year Unrealized and realized gains Purchases and settlements, net Balance at end of year 172 Enbridge Inc. 2016 Annual Report 2016 2015 297 22 2 321 132 44 121 297 Plan Contributions by the Company Year ended December 31, (millions of Canadian dollars) Total contributions Contributions expected to be paid in 2017 Beneﬁts Expected to be Paid by the Company Pension OPEB 2016 2015 2016 2015 102 148 116 9 2 10 Year ended December 31, (millions of Canadian dollars) 2017 2018 2019 2020 2021 2022 – 2026 Expected future beneﬁt payments 115 121 127 134 142 829 27. Other Income/(Expense) Year ended December 31, (millions of Canadian dollars) Net foreign currency gain/(loss) Allowance for equity funds used during construction Interest income on affiliate loans Interest income Noverco preferred shares dividend income Gains on dispositions Other 28. Severance Costs 2016 2015 2014 91 1 23 3 37 848 29 1,032 (884) (400) 2 20 4 40 94 22 3 20 3 42 38 28 (702) (266) Included in Operating and administrative and Other income/(expense) is $54 million and nil, respectively (2015 – $42 million and $4 million, respectively), for severance costs related to termination beneﬁts to employees. This resulted from an enterprise-wide reduction of workforce that occurred in October 2016 and November 2015 that affected approximately 5% of the Company’s workforce in each respective year. The amounts are included within Eliminations and Other. Of the total severance costs incurred in 2016, $29 million was paid in 2016 with the remaining $25 million to be paid in 2017 and is included in Accounts payable and other as at December 31, 2016. Of the total severance costs incurred in 2015, $22 million was paid in 2015 with the remaining $24 million paid in 2016. This amount was included in Accounts payable and other as at December 31, 2015. 29. Changes in Operating Assets and Liabilities Year ended December 31, (millions of Canadian dollars) Accounts receivable and other Accounts receivable from affiliates Inventory Deferred amounts and other assets Accounts payable and other Accounts payable to affiliates Interest payable Other long-term liabilities 2016 2015 2014 (437) (7) (371) (183) 396 71 20 153 (358) 698 82 (315) 364 (1,472) (26) 31 (7) (645) (83) (176) (186) (429) (822) 34 24 (61) (1,699) Notes to the Consolidated Financial Statements 173 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, 2016 (2015 – $7 million; 2014 – $7 million). Certain wholly-owned subsidiaries within the Liquids Pipelines, Gas Distribution, Gas Pipelines and Processing and Energy Services segments have committed and uncommitted transportation arrangements with several joint venture affiliates that are accounted for using the equity method. Total amounts charged to the Company for transportation services for the year ended December 31, 2016 were $357 million (2015 – $332 million; 2014 – $256 million). A wholly-owned subsidiary within Liquids Pipelines had a lease arrangement with a joint venture affiliate. During the year ended December 31, 2016, expenses related to the lease arrangement totalled $287 million (2015 – $151 million; 2014 – $21 million) and were recorded to Operating and administrative expense. Certain wholly-owned subsidiaries within Gas Distribution and Energy Services segments made natural gas and NGL purchases of $98 million (2015 – $228 million; 2014 – $315 million) from several joint venture affiliates during the year ended December 31, 2016. Natural gas sales of $49 million (2015 – $5 million; 2014 – $58 million) were made by certain wholly- owned subsidiaries within the Energy Services segment to several joint venture affiliates during the year ended December 31, 2016. Long-Term Notes Receivable From Affiliates Amounts receivable from affiliates include a series of loans to Vector and other affiliates totalling $130 million and $140 million, respectively (2015 – $149 million and $3 million, respectively), which require quarterly interest payments at annual interest rates ranging from 4% to 12%. These amounts are included in Deferred amounts and other assets. 31. Commitments and Contingencies Commitments At December 31, 2016, Enbridge had commitments as detailed below: (millions of Canadian dollars) Purchase of services, pipe and other materials, including transportation1,2 Capital and operating leases Maintenance agreements Land lease commitments Total 1 Includes capital and operating commitments. Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter 10,661 3,660 1,461 1,249 1,100 631 394 356 105 54 13 62 40 14 56 35 13 52 18 14 996 51 16 13 2,195 305 231 289 12,042 3,832 1,577 1,353 1,184 1,076 3,020 2 Includes commitments for transportation service agreements totalling $618 million which assume a light to heavy crude oil ratio of 80:20 on certain pipelines and a power charge of $0.06 per barrel. Enbridge Energy Partners, L.P. As at December 31, 2016, Enbridge holds an approximate 35.3% (2015 – 35.7%; 2014 – 33.7%) combined direct and indirect economic interest in EEP, which is consolidated with noncontrolling interests. 174 Enbridge Inc. 2016 Annual Report Lakehead System Lines 6A and 6B Crude Oil Releases the released crude oil went onto a roadway, into a storm sewer, Line 6B Crude Oil Release a waste water treatment facility and then into a nearby retention pond. All but a small amount of the crude oil was recovered. On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead EEP completed excavation and replacement of the pipeline System was reported near Marshall, Michigan. EEP estimates that segment and returned it to service on September 17, 2010. approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Kalamazoo River via Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 61 kilometres (38 miles) of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. EEP continues to evaluate the need for additional remediation activities and is performing the necessary restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives EEP is undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. In May 2015, EEP reached a settlement with the 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, 2016, EEP’s total cost estimate for the Line 6B crude oil release remains at US$1.2 billion ($195 million after-tax attributable to Enbridge) since December 31, 2015 and 2014. EEP has completed the cleanup, remediation and restoration of the areas affected by the release. In October 2013, the National Transportation Safety Board publicly posted their ﬁnal report related to the Line 6A crude oil release which states the probable cause of the crude oil release was erosion caused by a leaking water pipe resulting from an improperly installed third-party water service line below EEP’s oil pipeline. The total estimated cost for the Line 6A crude oil release was approximately US$53 million ($7 million after-tax attributable to Enbridge) before insurance recoveries and excluding ﬁnes and penalties. These costs included emergency response, environmental remediation and cleanup activities with the crude oil release. As at December 31, 2016, EEP has no remaining estimated liability. Insurance EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. On May 1 of each year, the commercial liability insurance program is renewed and includes coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents excluding costs for ﬁnes and penalties. Enbridge has renewed its comprehensive property and liability insurance programs with a liability program aggregate limit of US$900 million, which includes sudden and accidental pollution liability. The insurance programs are effective May 1, 2016 through April 30, 2017. In the unlikely event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among Enbridge entities on an equitable basis based on an insurance allocation agreement among Enbridge and its subsidiaries. This includes a reduction of estimated remediation efforts offset by A majority of the costs incurred in connection with the crude oil an increase in civil penalties under the Clean Water Act of the United release for Line 6B, other than ﬁnes and penalties, are covered by States, as described below under Legal and Regulatory Proceedings. Enbridge’s comprehensive insurance policy that expired on April 30, 2011, Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at December 31, 2016. Despite the efforts EEP has made to ensure the reasonableness of its estimate, there continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modiﬁed or revised requirements from regulatory agencies. Line 6A Crude Oil Release A release of crude oil from Line 6A of EEP’s Lakehead System which had an aggregate limit of US$650 million for pollution liability for Enbridge and its affiliates. Including EEP’s remediation spending through December 31, 2016, costs related to Line 6B exceeded the limits of the coverage available under this insurance policy. Additionally, ﬁnes and penalties would not be covered under prior or existing insurance policy. As at December 31, 2016, EEP has recorded total insurance recoveries of US$547 million ($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million aggregate limit. EEP will record receivables for additional amounts it claims for recovery pursuant to its insurance policies during the period it deems recovery to be probable. was reported in an industrial area of Romeoville, Illinois on In March 2013, EEP and Enbridge ﬁled a lawsuit against the insurers September 9, 2010. EEP estimates that approximately 9,000 barrels of US$145 million of coverage, as one particular insurer is disputing of crude oil were released, of which approximately 1,400 barrels the recovery eligibility for costs related to EEP’s claim on the Line 6B were removed from the pipeline as part of the repair. Some of crude oil release and the other remaining insurers asserted that their Notes to the Consolidated Financial Statements 175 payment is predicated on the outcome of the recovery from that implemented since 2010 to EEP’s leak detection program, control insurer. EEP received a partial recovery payment of US$42 million centre operations and emergency response program. EEP estimates from the other remaining insurers and amended its lawsuit such that the total cost of these measures to be approximately US$110 million, it includes only one insurer. Legal and Regulatory Proceedings most of which is already incorporated into existing long-term capital investment and operational expense planning and guidance. Compliance with the terms of the Consent Decree is not expected to materially A number of United States governmental agencies and regulators impact the overall ﬁnancial performance of EEP or the Company. have initiated investigations into the Line 6B crude oil release. Two actions or claims are pending against Enbridge, EEP or their Aux Sable affiliates in United States state courts in connection with the Notice of Violation Line 6B crude oil release. Based on the current status of these cases, the Company does not expect the outcome of these actions to be material to its results of operations or ﬁnancial condition. Line 6A and 6B Fines and Penalties As at December 31, 2016, included in EEP’s total estimated costs related to the Line 6B crude oil release were US$69 million in ﬁnes and penalties. Of this amount, US$61 million relates to civil penalties under the Clean Water Act of the United States, which EEP fully accrued but have not paid, pending approval of the Consent Decree, as described below. In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the United States EPA for alleged violations of the Clean Air Act related to the Leak Detection and Repair program, and related provisions of the Clean Air Act permit for Aux Sable’s Channahon, Illinois facility. As part of the ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believed to be an exceedance of currently permitted limits for Volatile Organic Material. In April 2015, a second NFOV from the EPA was received in connection with this potential exceedance. Aux Sable engaged in discussions with the EPA to evaluate the impacts and ultimate resolution of these issues, including with respect to a draft In June 2015, Enbridge reached a separate agreement with Consent Decree, and those discussions are continuing. The Consent the United States (Federal Natural Resources Damages Trustees), Decree, when ﬁnalized, is not expected to have a material impact. State of Michigan (State Natural Resources Damages Trustees), Match-E-Be-Nash-She-Wish Band of the Potawatomi Indians, and the Nottawaseppi Huron Band of the Potawatomi Indians, and paid approximately US$4 million that was accrued to cover a variety of projects, including the restoration of 175 acres of oak savanna in the Fort Custer State Recreation Area and wild rice beds along the Kalamazoo River. One claim related to the Line 6A crude oil release had been ﬁled against Enbridge, EEP or their affiliates by the State of Illinois in the Illinois state court in connection with this crude oil release. On February 20, 2015, EEP agreed to a consent order releasing it from any claims, liability, or penalties. Consent Decree On July 20, 2016, a Consent Decree was ﬁled with the United States District Court for the Western District of Michigan Southern Division (the Court). The Consent Decree is EEP’s signed settlement agreement with the EPA and the United States Department of Justice regarding Lines 6A and 6B crude oil releases. Pursuant to the Consent Decree, EEP will pay US$62 million in civil penalties: US$61 million in respect of Line 6B and US$1 million in respect of Line 6A. The Consent Decree will take effect upon approval by the Court. On October 14, 2016, an amended claim was ﬁled against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable ﬁled a Statement of Defence with respect to this claim. While the ﬁnal outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on the Company’s consolidated ﬁnancial position or results of operations. 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 In addition to the monetary ﬁnes and penalties discussed above, the Consent Decree calls for replacement of Line 3, which EEP position or results of operations. initiated in 2014 and is currently under regulatory review in the State of Minnesota. The Consent Decree contains a variety of injunctive 32. Guarantees measures, including, but not limited to, enhancements to EEP’s The Company has agreed to indemnify EEP from and against comprehensive in-line inspection-based spill prevention program; substantially all liabilities, including liabilities relating to environmental enhanced measures to protect the Straits of Mackinac; improved matters, arising from operations prior to the transfer of its pipeline leak detection requirements; installation of new valves to control operations to EEP in 1991. This indemniﬁcation does not apply product loss in the event of an incident; continued enhancement to amounts that EEP would be able to recover in its tariff rates of control room operations; and improved spill response capabilities. if not recovered through insurance or to any liabilities relating Collectively, these measures build on continuous improvements to a change in laws after December 27, 1991. 176 Enbridge Inc. 2016 Annual Report The Company has also agreed to indemnify EEM for any tax liability The Hohe See Offshore Wind Project is located in the North Sea, related to EEM’s formation, management of EEP and ownership 98 kilometres (61 miles) off the coast of Germany and will of i-units of EEP. The Company has not made any signiﬁcant payment be constructed under ﬁxed-price engineering, procurement, under these tax indemniﬁcations. The Company does not believe construction and installation contracts, which have been secured 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. with key suppliers. The Hohe See Offshore Wind Project is backed by a government legislated 20-year revenue support mechanism. Enbridge’s total investment in this project through the project’s completion and in-service date in 2019 is expected to be approximately $1.7 billion (€1.07 billion), including planned spend of approximately $0.6 billion (€0.44 billion) throughout 2017. The Company has also agreed to pay deﬁned payments to the Fund On February 15, 2017, EEP completed its previously disclosed Group on their investment in Southern Lights in the event shippers transaction to acquire an effective 27.6% interest in the Bakken do not elect to extend their current contracts post June 2025. Pipeline System for a purchase price of US$1.5 billion. The Bakken 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. Pipeline System connects the proliﬁc Bakken formation in North Dakota to markets in eastern PADD II and the United States Gulf Coast, providing customers with access to premium markets at a competitive cost. The Bakken Pipeline System consists of the Dakota Access Pipeline and the Energy Transfer Crude Oil Pipeline projects. The Dakota Access Pipeline consists of 1,886 kilometres (1,172 miles) of 30-inch pipeline from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois. It is expected to initially deliver in excess of 470,000 bpd of crude oil and has the potential to In the normal course of conducting business, the Company enters be expanded to 570,000 bpd. The Energy Transfer Crude Oil Pipeline into agreements which indemnify third parties and affiliates. Examples consists of 100 kilometres (62 miles) of new 30-inch diameter pipe, include indemnifying counterparties pursuant to sale agreements for 1,104 kilometres (686 miles) of converted 30-inch diameter pipe, assets or businesses in matters such as breaches of representations, and 64 kilometres (40 miles) of converted 24-inch diameter pipe warranties or covenants, loss or damages to property, environmental from Patoka, Illinois to Nederland, Texas. 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 Events On January 27, 2017, Enbridge announced that it had entered into a merger agreement through a wholly-owned subsidiary, whereby it will take private MEP by acquiring all of the outstanding publicly-held common units of MEP. Total consideration to be paid by Enbridge for these units will be approximately US$170 million and the transaction is expected to close in the second quarter of 2017. In addition, pursuant to an on-going strategic review of EEP, further joint funding actions with EEP were announced. Speciﬁcally, Enbridge and EEP entered into an agreement for the joint funding of the United States portion of the Line 3 Replacement Program (U.S. L3R Program), whereby Enbridge and EEP will fund 99% and 1%, respectively, of the project development and construction costs. Enbridge has reimbursed EEP approximately US$450 million for capital expenditures on the project to date and will fund 99% of the expenditures through construction. EEP will retain an option to acquire up to 40% of the U.S. L3R Program at book value, once the project is completed and in service. EEP also used a portion of the proceeds reimbursed by Enbridge under the U.S. L3R joint funding arrangement to acquire an additional 15% interest in the cash-generating Eastern Access projects pursuant to an existing On February 17, 2017, the Company announced it had acquired joint funding agreement for approximately US$360 million. an effective 50% interest in the partnership that will construct the The strategic review of EEP is ongoing and it is currently expected 497-MW Hohe See Offshore Wind Project. Enbridge will partner with that any resulting actions will be announced early in the second state-owned German utility EnBW in the construction and operation quarter of 2017. Any such contemplated actions are not expected of this late-design project, with the target in-service date of 2019. to be material to Enbridge’s previously published ﬁnancial projections. Notes to the Consolidated Financial Statements 177 Glossary ACFFO ALJ Available cash ﬂow from operations Administrative Law Judge EGD EGNB Enbridge Gas Distribution Inc. Enbridge Gas New Brunswick Inc. Alliance Pipeline Canada Canadian portion of Alliance Pipeline EIPLP Enbridge Income Partners LP Alliance Pipeline US United States portion of Alliance Pipeline Average Exchange Rate United States to Canadian dollar average exchange rate for a period/year Enbridge or the Company Enbridge Inc. ENF EPAI EPI Enbridge Income Fund Holdings Inc. Enbridge Pipelines (Athabasca) Inc. Enbridge Pipelines Inc. bcf/d bpd Cabin Billion cubic feet per day Federal Court Federal Court of Appeal Barrels per day Cabin Gas Plant FERC Federal Energy Regulatory Commission Flanagan South Flanagan South Pipeline Canadian L3R Program Canadian portion of the Line 3 CSR CTS EBIT ECT EELP EEP Replacement Program Corporate Social Responsibility Competitive Toll Settlement GHG GP GTA Greenhouse gas General partner Greater Toronto Area Earnings before interest and Heidelberg Pipeline Heidelberg Oil Pipeline income taxes Enbridge Commercial Trust Enbridge Energy, Limited Partnership Enbridge Energy Partners, L.P. IDR IJT Incentive Distribution Rights International Joint Tariff L3R Program Line 3 Replacement Program 178 Enbridge Inc. 2016 Annual Report Lakehead System Lakehead Pipeline System ROE Return on equity LNG MD&A MEP MNPUC MPC MW NEB NGL Liqueﬁed natural gas Seaway Pipeline Seaway Crude Pipeline System Management’s Discussion Spectra Energy Spectra Energy Corp and Analysis Midcoast Energy Partners, L.P. Stampede Pipeline Stampede Oil Pipeline the Certiﬁcate(s) Certiﬁcate(s) of Public Convenience Minnesota Public Utilities Commission and Necessity under the authority Marathon Petroleum Corporation Megawatts National Energy Board Natural gas liquids of the NEB the Fund Enbridge Income Fund the Fund Group The Fund, ECT, EIPLP and the subsidiaries and investees of EIPLP the Tupper Plants Tupper Main and Tupper West Norlite Norlite Pipeline System gas plants Northern Gateway Northern Gateway Project U.S. GAAP Noverco Offshore ORM Plan PPA(s) Noverco Inc. Enbridge Offshore Pipelines Operational Risk Management Plan Power purchase agreement(s) Rampion Project Rampion Offshore Wind Project RGP Rich Gas Premium Generally accepted accounting principles in the United States of America U.S. L3R Program United States portion of the Line 3 Vector WCSB WTI Replacement Program Vector Pipeline Western Canadian Sedimentary Basin West Texas Intermediate Glossary 179 Three-Year Consolidated Highlights Year ended December 31, (millions of Canadian dollars, except per share amounts) Earnings attributable to common shareholders Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other Earnings before interest and income taxes Interest expense Income taxes recovery/(expense) (Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests Preference share dividends Earnings/(loss) attributable to common shareholders Discontinued operations – Gas Pipelines and Processing Earnings/(loss) per common share Diluted earnings/(loss) per common share Adjusted earnings Liquids Pipelines Gas Distribution Gas Pipelines and Processing Green Power and Transmission Energy Services Eliminations and Other Adjusted earnings before interest and income taxes2 Interest expense3 Income taxes3 Noncontrolling interests and redeemable noncontrolling interests3 Discontinued operations Preference share dividends Adjusted earnings2 Adjusted earnings per common share1 Cash ﬂow data Cash provided by operating activities Cash provided by/(used in) investing activities Cash provided by ﬁnancing activities Available cash ﬂow from operations4 Available cash ﬂow from operations5 Available cash ﬂow from operations per common share5 Dividends Common share dividends declared Dividends paid per common share Shares outstanding (millions) Weighted average common shares outstanding Diluted weighted average common shares outstanding6 20161 20151 20141 3,557 492 171 154 (185) (148) 4,041 (1,590) (142) (240) (293) 1,776 – 1,776 1.95 1.93 1,806 455 (229) 177 325 (899) 1,635 (1,624) (170) 410 (288) (37) – (37) (0.04) (0.04) 3,958 3,384 494 366 165 28 (349) 4,662 (1,545) (520) (226) – (293) 2,078 2.28 5,211 (5,192) 1,102 3,713 4.08 1,945 2.12 911 918 446 336 175 61 (246) 4,156 (1,273) (486) (243) – (288) 1,866 2.20 4,571 (7,933) 2,973 3,154 3.72 1,596 1.86 847 847 1,980 432 467 149 730 (456) 3,302 (1,129) (611) (203) (251) 1,108 46 1,154 1.39 1.37 2,592 391 293 151 42 (60) 3,409 (926) (434) (225) 1 (251) 1,574 1.90 2,547 (11,891) 9,770 2,506 3.02 1,177 1.40 829 840 1 Effective January 1, 2016, the Company revised its reportable segments and reported Earnings before interest and income taxes for each reporting segment which also resulted in a reclassiﬁcation of the comparative information for 2015 and 2014. 2 Adjusted EBIT, adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by GAAP – see Non-GAAP Measures. 3 These balances are presented net of adjusting items. 4 ACFFO is deﬁned as cash ﬂow provided by operating activities before changes in operating assets and liabilities (including changes in environmental liabilities) less distributions to noncontrolling interests and redeemable noncontrolling interests, preference share dividends and maintenance capital expenditures, and further adjusted for unusual, non-recurring or non-operating factors. ACFFO and ACFFO per common share are non-GAAP measures that do not have any standardized meaning prescribed by GAAP. 5 ACFFO was introduced in 2015 with two years of comparative information and one year of comparative information for ACFFO per common share. 6 The diluted weighted average common shares outstanding excludes 11 million stock options for the year ended December 31, 2015 as their effect would be anti-dilutive due to the loss attributable to common shareholders for the period. 180 Enbridge Inc. 2016 Annual Report Three-Year Consolidated Highlights (millions of Canadian dollars; per share amounts in Canadian dollars) Common share trading (TSX) High Low Close Volume (millions) Financial ratios Return on average equity1 Return on average capital employed2 Debt to debt plus total equity3 Dividend payout ratio4 Operating data Liquids Pipelines – Average deliveries (thousands of barrels per day) Canadian Mainline5 Lakehead System6 Regional Oil Sands System7 Gas Pipelines – Average throughput (millions of cubic feet per day) Alliance Pipeline Canada Alliance Pipeline US Gas Distribution – Enbridge Gas Distribution Inc. (EGD) Volumes (billions of cubic feet) Number of active customers (thousands)8 Heating degree days Actual9 Forecast based on normal weather volume 2016 2015 (cid:31) (cid:31) (cid:31) (cid:31) 45.77 27.43 42.12 442 8.7% 4.5% 62.1% 93.0% 2,405 2,574 1,032 1,532 1,668 414 2,158 3,412 3,617 66.14 40.17 46.00 416 (0.2%) 2.3% 65.5% 84.5% 2,185 2,315 1,004 1,488 1,645 437 2,129 3,710 3,536 (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) (cid:31) (cid:31)(cid:31) (cid:31) (cid:31) 1 Earnings applicable to common shareholders divided by average shareholder’s equity. 2 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). 3 Total debt (including short-term borrowings) divided by the sum of total debt and total equity inclusive of noncontrolling interests and redeemable noncontrolling interests. 4 Dividends per common share divided by adjusted earnings per common share. 5 Canadian Mainline throughput volume represents mainline system deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada. 6 Lakehead System throughput volume represents mainline system deliveries to the United States mid-west and eastern Canada. 7 Volumes are for the Athabasca mainline, Waupisoo Pipeline and Woodland 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 Greater Toronto Area. Three-Year Consolidated Highlights 181 Investor Information Common and Preference Shares Registrar and Transfer Agent The Common Shares of Enbridge Inc. trade in Canada on the For information relating to share-holdings, share purchase plan, Toronto Stock Exchange and in the United States on the New York dividends, direct dividend deposit, dividend re-investment accounts Stock Exchange under the trading symbol “ENB.” The Preference and lost certiﬁcates, please contact: 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 In Canada: CST Trust Company P.O. Box 700, Station B Montreal, Quebec H3B 3K3 Canada Telephone: 800-387-0825, or 416-682-3860 outside of North America canstockta.com Series N – ENB.PR.N Series 15 – ENB.PF.G CST Trust Company also has offices in Halifax, Toronto, Calgary Series P – ENB.PR.P Series 17 – ENB.PF.I and Vancouver. Series R – ENB.PR.T 2017 Enbridge Inc. Common Share Dividends Dividend Q1 $0.583 Q2 $ – 4 Q3 $ – 4 Q4 $ – 4 In the United States: AST 6201 – 15th Avenue Brooklyn, New York U.S.A. 11219 Payment date Mar 01 Jun 01 Sep 01 Dec 01 Telephone: 800-937-5449 Record date1 SPP deadline2 Feb 15 May 15 Aug 15 Nov 15 amstock.com Feb 22 May 25 Aug 25 Nov 24 DRIP Information and How to Register DRIP enrollment3 Feb 08 May 08 Aug 08 Nov 08 Enbridge offers a dividend reinvestment and share purchase plan 1 Dividend record dates for Common Shares are generally February 15, May 15, August 15 (DRIP) to enable holders of Enbridge common shares to acquire 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. additional shares through re-investment of the common share dividends paid quarterly, or through optional cash payments. 3 The Dividend Reinvestment Program enrollment cut-off date is ﬁve business days Dividends re-invested through Enbridge's DRIP receive a two-percent 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 182 Enbridge Inc. 2016 Annual Report discount on the market price of Enbridge shares, and funds are fully invested as fractional share ownership is permitted as part of the plan. DRIP participants are also eligible to purchase up to an additional $5,000 in Enbridge common shares each quarter without incurring brokerage fees; however, the two-percent discount is not available for these additional purchases. Please contact CST toll-free (North America) at 1-800-387-0825 or outside of North America at 1-416-682-3860 to request enrollment forms and for further information on Enbridge's DRIP. 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. Annual Meeting The Annual Meeting of Shareholders will be held in the Ballroom at the Metropolitan Conference Centre, 333 – 4 Avenue S.W., Calgary, AB, Canada at 1:30 pm MT on Thursday, May 11, 2017. 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 . s s e r P e t t e h c n a B y b d e t n i r P l . t t e n r u B o e L y b d e c u d o r p d n a d e n g s e D i 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 annual 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 2016 report is available online at csr.enbridge.com Online Annual Report You can read our 2016 Annual Report online at enbridge.com/ar2016 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 2017, Enbridge was named to the Global 100 for the eighth straight year, and 11th time overall. Enbridge is ranked No. 39 worldwide, up from our No. 46 overall ranking in 2016 – and third among Canadian corporations. In 2016, 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 nine times in the past 10 years, and named to the World Index seven times, including the past ﬁve 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

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