TC Energy Corporation (TSX:TRP)

Investor Day 2015

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Nov 17, 2015

Again, good morning and welcome to TransCanada's 2015 Investor Day. I'm David Moneta, Vice President of Investor Relations at TransCanada. It is clearly an interesting time in the history of our company and of our industry. We hope to use this morning to provide you with some insight into the many initiatives that are underway and are expected to create significant shareholder value. We also hope to provide some insight into the trends that will help shape the future in both the pipeline and energy businesses. We'll begin today with Russ Girling, our President and Chief Executive Officer. Russell will provide some comments on our vision, our progress over the past five years, our priorities going forward, and our long-term outlook. He'll be followed by Alex Pourbaix, Karl Johannson, Paul Miller, Bill Taylor, who will provide you with more detailed updates on each of our businesses. Finally, Don Marchand, our Chief Financial Officer, will close out the morning with a finance update. Copies of the agenda and their presentations are included in your handout. For those of you listening via webcast, a copy of our presentation materials are on our website, and they can be found in the Investors section under the heading Events and Presentations. We will provide you with a number of opportunities to ask questions this morning. I would ask that you limit yourself to one question and a follow-up to the extent that we can continue to move the mic around and give everybody an opportunity. That would be great. Before I begin, obviously, we would like to highlight that our comments this morning will include forward-looking statements that are subject to certain risks and uncertainties. For more information on those risks and uncertainties, please see documents filed with the Canadian Securities Administrators and the U.S. Securities and Exchange Commission. Finally, just a quick word on non-GAAP measures. We will touch base this morning on a number of non-GAAP items, including earnings before interest, taxes, depreciation, and amortization or EBITDA, funds generated from operations, and distributable cash flow. These are non-GAAP measures as defined under U.S. GAAP and, as a result, may not be necessarily comparable to the same measures used by other entities. We do feel they're important in terms of giving you a better sense of our outlook, as well as our ability to continue to fund our capital program and pay dividends going forward. With that, I'll turn the podium over to Russ Girling, our Chief Executive Officer. Thanks, David, good morning, everybody, and thank you very much for taking time out of your busy schedules to join us here today. We very much appreciate your interest and continued support of our company. Time flies pretty quick. It's hard to believe it's only been 12 months since we were here last. Looking back at the year, we've had a couple of bumps along the road, but I'm pretty pleased with the progress that we've continued to make in what I'd call one of the most challenging environments our industry's seen in some time. Over the next few hours, my executive team and I look forward to sharing with you some of those significant advances, as well as some of the challenges that we faced, and I think probably most importantly, the promising outlook that we see for many years yet to come. In the short, we've largely resolved a lot of the headwinds that affected certain parts of our businesses over the last few years. Today, despite what I say is CAD 40 oil, CAD 2 natural gas, CAD 0.30 storage spreads, and CAD 20 Alberta power prices, our base businesses are performing very well. We continue to add new projects to our portfolio of high-quality opportunities. Looking forward, we believe that maximizing the value of our existing assets, as well as advancing that portfolio of commercially secured projects, will continue to create significant shareholder value for the long term. Simply put, our strategy is unchanged. It's about remaining disciplined, growing earnings, growing cash flow, growing dividends per share over both the short and the long term. We'll cover a lot of things this morning. I believe this slide captures the key themes of what we want to talk to you about today. 15 years ago, we set out to become North America's leading energy infrastructure company with a focus on pipelines and power generation. We do regularly review our strategic alternatives. We've largely stuck to that strategy, and it's produced an average annual shareholder return of 13% since 2000, despite the current fall in our stock price. Second, our three core businesses are performing very well in 2015, as I said, with EBITDA and funds generated from operations expected to reach record levels, again, despite those challenging commodity prices that I mentioned. Looking forward, we remain confident that our high-quality portfolio of critical energy infrastructure assets will continue to produce solid results for many years to come through all market conditions. Third, although the environment in which we operate has become increasingly complex, we are prepared for that challenge, and we continue to be a leader in setting new standards for safety, reliability, and environmental stewardship throughout our three core businesses. At the same time, we have focused our attentions on generating efficiencies in our operations, streamlining our decision-making process. This will all result in lower costs for both TransCanada, a better competitive position, and lower costs for our customers. We'll also maintain our disciplined approach to capital allocation with a focus on generating superior risk-adjusted returns for our shareholders, both in the near term and in the long term. Fourth, our industry-leading portfolio of commercially secured projects now includes CAD 13 billion of small to medium-sized projects that are expected to be in service by 2018. We continue to advance a number of other growth opportunities outside of our large portfolio. As well, we have a large portfolio of larger scale projects that are about CAD 35 billion. Any one of those initiatives would create significant incremental shareholder value and position us for continued long-term growth. We do understand the importance and value that our shareholders place on a strong and growing dividend. Based on our positive outlook for the future and strong dividend coverage ratios, we expect to grow that dividend at an average annual rate of 8%-10% through 2020. In summary, we believe that we have a strong, compelling investment proposition on both a fundamental basis and a relative basis, given the stability of our underlying operations, our outlook for growth, and our industry-leading dividend coverage ratios. To dive into the presentation here, this map highlights the scale and scope of our operation today, quite substantially different than it was 15 years ago. Today, TransCanada is one of the largest natural gas transmission companies in North America and the third-largest gas storage company in North America. We are a significant player in the liquids transportation business now with the Keystone Pipeline system that's delivered about 1.3 billion barrels of oil to the U.S. We are the largest and most successful private sector power company in Canada. With an enterprise value of about CAD 65 billion, today, we have interest in or we own about 68,000 kilometers of pipe, a natural gas pipe that moves about 20% of all the gas that moves in North America. We have 370 Bcf of gas storage. The Keystone Pipeline is now operating at a rate of about 545,000 barrels per day. We have 19 power plants that deliver about 11,000 megawatts to millions of customers in both Canada and the U.S. This large and diversified portfolio of high-quality assets is critical delivering the energy that North America needs and provides us with an enviable position upon which to continue to grow this company. Well, Keystone has attracted a lot of headlines over the last five years. When I say a lot, this last couple of weeks, it's a couple thousand news stories. Despite that, there's a lot of other things going on in the company, and we've made quiet progress on a number of those fronts, and I want to share those with you today just to highlight just how important those other things are. Over the last five years, we've placed CAD 20 billion of assets into service. We've captured CAD 40 billion of new opportunities. We've raised CAD 10 billion of capital in the capital markets, net of maturities, and dropped CAD 2.5 billion of assets into our MLP to help fund our capital program. We also paid more than CAD 6 billion in dividends to our shareholders. While our share count has essentially remained the same since early 2001, when we eliminated the discount on our dividend reinvestment program, we are one of the few that now have maintained an A-grade credit rating, and as a result of our disciplined capital allocation approach. We've also resolved a number of issues that affected parts of our business. You need to grab some water there. Thanks. Sorry about that. As I said, we've resolved a number of issues that have affected our business over the last few years. I think the most important example is that through our long-term settlement on our Canadian mainline, and significant new long-term contracts on ANR, we effectively turned what I call threats posed by the shale gas revolution into high-quality opportunities on our long-haul natural gas pipelines. Today, those systems, along with NGTL, are benefiting from the significant rise in North American natural gas production. Karl will talk a little bit about that later. Finally, we recently initiated a restructuring plan that will decentralize many of our operating, project, and functional support groups, placing greater accountability into the business units, and they will be the ones to determine their resource requirements on a go-forward basis. The restructuring, as I said, is expected to lower our costs for both TransCanada and our customers as they're implemented through 2015 and into 2016. As you can see from this chart, this isn't all the things that we've done, many more. You can see that the story is much bigger than Keystone XL. That said, we remain extremely disappointed with the recent decision of the denial by the President on our permit to build that pipeline. Through the course of that review, the U.S. State Department issued five comprehensive scientific reviews of the project that show that it is the safest, most environmentally sound way to transport the energy Americans need every day. Ultimately, at the end of the day, rhetoric won over reason. Despite that decision, our shippers remain supportive of the project, and we'll continue to review all of our options, and we'll be sharing that in the coming weeks and months with you as we decide which direction we're going to go. This slide highlights, from the previous page, the CAD 20 billion of assets that we've placed into service over the last five years. Essentially, all of these projects are underpinned by long-term contracts or cost-of-service business models. As you can see, it's a diverse suite of assets in all three of our core businesses. It includes our base Keystone system that's now delivering over CAD 1 billion of EBITDA, significant expansion of the NGTL system, our Mexican natural gas pipeline system, and the refurbishment of Bruce 1 and 2, and a number of new gas-fired and renewable power plants. In addition to contributing to the growth in earnings and cash flow over the last five years, each of these assets has effectively helped create new organic growth platforms in each of our three core businesses that will provide TransCanada with additional opportunities for decades yet to come. We'll talk about those throughout the morning. This slide highlights the growth in EBITDA and funds generated from operations over the last five years that's generated from those new assets. As you can see, comparable EBITDA has grown from about CAD 3.7 billion to an estimated CAD 5.8 billion, which represents a 10% average annual growth rate in EBITDA. At the same time, funds generated from operations have grown from about CAD 3.2 billion to an estimated CAD 4.5 billion for an average annual growth rate of about 7%. As a result of our past performance, our board of directors has had a long history of raising the dividend. As you can see from these charts, the dividend has increased from about CAD 1.60 in 2010 to its current rate of CAD 2.08. That represents a compound average growth rate of about 5% over that five-year period. At the same time, we've maintained industry-leading coverage ratios, with our current dividend representing about 85% of earnings and 35% of internally generated cash flow. In comparison with many of our peers that have pushed the payout ratios well beyond that to in excess of 100% of earnings, and in some cases, anywhere from 50%-100% of free cash flow. We believe that our strong financial position, growing cash flow, means we're well-positioned to prudently fund our capital programs and accelerate dividend growth through the end of the decade. Looking forward, the fundamentals in our business are expected to continue to offer us opportunities to build additional energy infrastructure in North America. I think one only needs to look at the map of our assets, you can see that we're well-positioned in those regions where new activity is going to take place. As I mentioned earlier, we have placed and invested about CAD 20 billion in high-quality assets over the last five years. That investment has been evenly split between all three of our businesses, with about CAD 8 billion going into liquids pipeline business, about CAD 6 billion going to our natural gas pipelines business, and about CAD 5 billion going into power generation. As a result, today, we do have three very strong platforms for growth in three geographies, both Canada, the U.S., and Mexico. It's always important to us to maintain that diversified portfolio. As you know, investment in any one line of business at some point in the cycle doesn't make sense, and at other points in time, it does. Through our diversification, along with a disciplined approach to capital allocation, we ensure that we only invest when the time is right and not be pressured into investing in the cycle when the time is wrong. The current time, with all the things going on, it may be difficult to look beyond next week or even next month, next year, in light of the difficult macro environment we find ourselves in. I think you can see from these charts here today that we try to take a long-term view and put things into perspective. Based on the IEA's 2015 World Energy Outlook, which just came out last week, it shows that despite the current turmoil in the global economy, the world demand for energy is expected to grow by about a third between now and 2040. It also highlights that in order to meet the demand, increasing amounts of energy will need to come from all sources of energy. As you can see, oil, coal, gas, nuclear, hydro, renewables, it's going to be required from all sources. We will generate considerably more energy from renewables and natural gas. I think, again, what's important on this slide is that oil will continue to be the largest source of energy for the next 25 years, according to the world's largest and most respected energy forecasting agency, and I don't think that's any different than any of the other forecasters that are out there. If you look at this slide, it's taking that global oil supply-demand chart and breaking it down by region. It highlights that the supply in North America will continue to grow, and over that time, North America is expected to become a net exporter of oil. That's on a continental basis, just to be clear. The bars show you the supply in each region, the dashed lines show the demand in each region over time. As I said, North America is expected to be self-sufficient on a continental basis. To be clear, North America will produce more than it consumes. The U.S. market will be a net importer for some time yet to come. By the U.S. Energy Information Administration's own forecast, they would suggest that between now and 2040, they'll still be importing somewhere between six and seven million barrels a day under almost any scenario. I think, as we've said before, we continue to be focused on that market as well as others, Canada is likely the most reliable and logical supplier to supply that 6 million-7 million barrels a day that the U.S. is going to need over the next 25 years. In addition, as you can see, the other markets that are going to continue to need supply is the European Union and Asia Pacific regions. They'll be large importers of oil. From my perspective, this highlights the need, in the long term, for new North American energy infrastructure that allows us to connect not only the growing domestic supply to growing domestic markets and reduce our dependence on foreign imports across the country. That's both in the U.S. and in Canada. Canada still imports about 700,000 barrels a day of its oil. It also highlights the need for Canada to access international markets if we hope to develop that vast resource over time. Energy East and Keystone XL will play an important role in meeting those needs over the longer term. If we flip over to gas and power from a fundamental perspective, as you can see from the chart on the left-hand side, North American natural gas is expected to grow by approximately 30 Bcf a day between now and 2030. Much of that supply will be used to fuel natural gas-fired generation facilities as we transition off coal, meet growing industrial demand, and to supply future LNG export terminals. Our extensive North American natural gas pipeline network is well-positioned to play an important role in connecting that growing supply to growing North American markets. Through our proposed West Coast LNG pipelines and the reversal of our ANR system, we're well-positioned to play a leading role in transportation of that natural gas supply to LNG export facilities. On the power front, which is on the right-hand side of this chart, you can see that new generation will be needed to meet growing demand and to replace aging infrastructure, and again, the transition from coal-fired generation across North America to some other form of energy. Renewables will play a large role as a result of government policy, renewable portfolio standards, and future GHG reduction targets, we're well-positioned to play a role in that. However, given the abundant supply of natural gas and its continually decreasing price, it is likely that gas-fired generation will play the most significant role in meeting that demand going forward. Today, we are a leader in the development of state-of-the-art natural gas fire generation with facilities like our Halton Hills plant that's just outside of Toronto here, the Portlands Energy Centre that's downtown Toronto here, the Napanee facility, another 1,000-megawatt facility that we have underway in Kingston right now. With the potential for gas fire capacity additions and replacements in our other core markets like Alberta, the Northeast U.S., and Mexico, I think we're well-positioned to capture additional opportunities in all of those markets as they evolve. In addition, we expect that nuclear power will continue to play an important role as we transition from a more carbon-intensive energy mix to a less carbon-intensive energy mix. We do own a significant interest in the world's largest nuclear-generating facility in Bruce Power. Ontario's commitment to nuclear power as part of their long-term energy plan should present opportunities for further investment in that facility over time. Going forward, we remain focused on the six key priorities that we've focused on for the last 15 years. The first, delivering energy safely and reliably every day to the folks across North America that need it and rely upon us. Second, we'll maximize the value of our existing assets by increasing revenues and reducing costs wherever we can. Third, we'll complete our CAD 13 billion of small-to-medium-sized projects that will drive significant growth over the next three years. Fourth, we'll continue to advance our CAD 35 billion portfolio of large-scale projects in a very cost-effective and contained manner. Fifth, we'll continue to cultivate a portfolio of additional low-risk opportunities in all of our core geographies and all of our core businesses. Finally, we'll maintain our financial strength and flexibility to ensure that we can prudently pay for our capital program and pay sustainable and growing dividends to our shareholders over the long call. You'll hear more about each of those as we go through the day from my presenters, but I wanted to present you sort of what it all adds up to here. As to the extent that we're able to execute that plan, it will result in significant future growth. As you can see from this slide, financially, if we continue to invest approximately CAD 5 billion a year or about CAD 26 billion in total between now and the end of the decade, which is equivalent to our discretionary cash flow and our debt capacity after dividends, we expect to grow EBITDA at a compound average annual rate of 8%. This is shown at the bottom by the bottom arrow on that chart. This is similar to what we've been saying for years and years and years. If we reinvest our cash flow at that kind of rate, we will generate a growth rate of about 7%-8%. We think it's actually going to be higher than that now. If you look back over history, that's exactly what we've done. Alternatively, if we're successful in advancing our entire CAD 48 billion portfolio of commercially secured projects, EBITDA would nearly double from about CAD 5.8 billion in 2015 to about CAD 11 billion exiting 2020. That would result in an average annual growth rate of about 14% over the remainder of the decade, which provides considerable upside to our shareholders if we're successful in moving those large-scale projects from concept into operation. Today, we have CAD 13 billion of small-to-medium-sized projects that are largely expected to enter service between now and 2018. The majority of those projects, as I said earlier, are underpinned by long-term contracts or regulated cost-of-service business model, which gives us a high degree of visibility to the future EBITDA and cash flow growth that will come from those assets. Once completed, those assets, combined with the underlying base businesses, are expected to produce EBITDA of about CAD 7 billion annually, which represents an average annual growth rate of about 8% between now and 2018. To the extent that we advance another CAD 13 billion of projects between now and the end of the decade, we'll extend that 8% right through to 2020. While this might seem like large numbers, I guess what I would tell you is that Excuse me again. Over the last month or so, I think you see us add about CAD 2 billion of high-quality new opportunities in our core businesses. My experience has been, if you look back over the last five years, we found CAD 20 billion worth of things to do. If you look back at the five years previous to that, we found CAD 20 billion worth of things to do. Looking forward, I don't think CAD 13 billion is that large of a portfolio for us to accumulate off the base position that we have today. Similarly, if we just advance one or two of our large-scale projects between now and the end of the decade, you can see that those would go a long way to securing that 8% growth rate without any additional capture of any new opportunities. Looking at it from a number of different ways, I've got pretty good confidence that we'll be continuing to find opportunities to fill in that CAD 13 billion of investment between now and between 2018 and the end of the decade. Flipping to our dividend is based on the confidence we have in our base businesses over the next three years and the associated growth in cash flow and earnings, and that confidence that I mentioned in terms of future growth. We expect to accelerate our dividend growth rate relative to the last five-year period. As I mentioned earlier, we do understand the value that our shareholders place on a strong growing dividend. After raising the dividend at CAD 0.08 a share, approximately 4% in each of the last four years, earlier this year, as you know, we raised the dividend by CAD 0.16 or about 8%. Looking forward, our strong and growing cash flows as well as our industry-leading dividend coverage ratios, we're well-positioned to continue to grow that dividend at an average annual rate of 8%-10% through 2020. At the same time, even at those kind of rates, it will leave us with ample financial flexibility to prudently fund our capital program and maintain our A-grade credit rating. As we successfully add to that CAD 13 billion portfolio of opportunities that we currently have on the slate, obviously, depending on what those look like, we will consider augmenting that 8%-10% growth rate through the end of the decade. In summary, I'd leave you with the following sort of key takeaways before my team gets up here. Today, we are a leading energy infrastructure company with a strong track record of delivering long-term shareholder value. We have CAD 66 billion of high-quality assets and more than 5,000 talented employees and well-positioned to take advantage of what I would say is an unprecedented opportunity and to deal with the difficult challenges that lie ahead. As we advance our industry-leading portfolio of commercially secured low-risk projects, we'll enhance our competitive position in each of our three core businesses and deliver significant growth in earnings, cash flow, and dividends. In addition, as evidenced by the fundamental long-term outlook for natural gas, crude oil, and power, there will be significant opportunities to continue to reinvest our strong growing cash flow in all of our core businesses and all of our core geographies. Although the environment in which we operate will become increasingly complex, we are well prepared for those challenges and will continue to be a leader in setting new standards for safety, reliability, and environmental stewardship. Through a disciplined approach and a careful execution of our plan, as we've always done, I am very confident that we will achieve our vision of being the leading energy infrastructure company in North America, and we'll continue to generate superior risk-adjusted returns for our shareholders. Before I conclude, I'd like to offer just a few comments about our executive leadership team, that we've made some changes on recently, and our employees. As I've always said as well, we have great assets, and we do. They're unparalleled in North America. As you know, they don't produce results without significant human ingenuity and human expertise. While I'm a bit biased, I have been at this business for about 30 years, and I believe that we've assembled the best talent in the industry, starting with our executive management team. Many of you are familiar with the faces that are on the chart here today. A lot of them are here. Alex is up here at the front. In the back, Karl, Paul, Don, and Kristine are also here today to provide you with an update on their respective businesses, and they'll be around for lunch as well. Feel free to ask them any questions that you want. They are a very talented group of leaders with a wealth of industry experience, and I'm extremely confident of their abilities to lead TransCanada through the difficult challenges that we have ahead, but as well, capitalize on the opportunities that are in front of us. I'd also like to acknowledge TransCanada's 5,000 talented employees in Canada, the U.S., and Mexico. They are experts in their chosen fields, and they do work tirelessly on behalf of our shareholders every day. I'm extremely proud of their accomplishments in 2015. Make no mistake, it is those 5,000 employees that operate CAD 66 billion worth of assets that will be the reason for our success in the future. That concludes my prepared remarks here today. I'll turn it over to Alex. He'll provide you with a bit more detail of our business outlook. Then following that, Alex and I will jointly answer some questions before we get into details from the business units. Alex? Thanks, Russ, good morning, everybody. It's great to be here in my new role as Chief Operating Officer, and I guess as COO, I'm responsible for the overall growth and performance of our three business units. You heard Russ talk a little bit about our recent reorganization, and I'm personally very confident that this reorganization has given our three presidents the tools they need to drive performance and safety improvements, cost reductions, and growth initiatives within their respective businesses. My role is to make sure that those business units deliver on their objectives while maintaining and improving operational performance and safety. Russ spent a bit of time highlighting our strong track record over the past five years and provided a high-level outlook of the company going forward. I thought today that I would spend a little bit of time digging deeper into the company's near-term priorities and initiatives. I thought I'd spend just a couple of minutes talking about what I think our competitive advantages are. While 2015 has been a very challenging year for the energy industry, with the impact of lower oil and gas prices being felt throughout the value chain, our diverse portfolio of critical energy infrastructure assets has continued to perform very well. Our pipelines and power generation facilities meet the energy needs of millions of North American families, businesses, and essential public services, and they will continue to do so for decades to come. Second, as Russ mentioned, our 5,000 employees in Canada, the U.S., and Mexico really are our competitive advantage. They are experts at operating large-scale energy infrastructure and developing creative solutions to meet the needs of our customers while putting in place commercial arrangements that strike the right risk-reward balance for our shareholders. Today, we're at the top of our industry in terms of operating performance, we recognize the need to continually improve. It is this commitment that will allow us to successfully navigate today's complex environment and continue to build and operate the infrastructure that North America needs. Third, over the past 15 years, we have invested over CAD 40 billion in high-quality energy infrastructure assets. In the process, we have built much more than just assets. We have built significant platforms for future growth in the natural gas pipeline business, the liquids pipeline business, and power generation in North America. Looking forward, we believe that our asset footprint will provide us with significant organic growth opportunities for decades to come. Finally, our financial strength and flexibility is another important competitive advantage, and never more so than in today's tough environment. I think everybody in this room understands that the largest cost of doing business for TransCanada, and everyone in our industry, is the cost of money. With an A-grade credit rating and significant internally generated cash flow, we really are well-positioned to continue to fund our growth and pay a strong and growing dividend to our shareholders. In addition to our competitive strengths, we have a long history of working collaboratively with landowners, First Nations, local businesses, and other stakeholders in the communities where we work. We treat our over 60,000 landowners with fairness and respect, that has allowed us to build really successful long-term relationships with them. Our assets are in the ground for decades, we've long ago learned that maintaining these relationships are very important. As we look to develop new projects, our approach is the same. Understanding stakeholder issues and engaging with local officials and landowners to identify how to best address their concerns is critical to our success as we develop and construct linear facilities. We also actively work to promote Aboriginal participation and involvement by supporting communities and hiring businesses or individuals to work on our pipeline projects. The experience we've had on our two LNG pipes in B.C., I think, is ample evidence of our commitment to work with Aboriginal communities. Responsible development and a commitment to protecting the environment are just as important as engagement with stakeholders. While these efforts are taking more upfront time and cost more, they will help us gain the social acceptance that is necessary for many of our projects to proceed. In summary, while counterparties will always be looking for competitively priced infrastructure services, they recognize the challenge our industry is facing, and they are becoming much more selective in choosing a partner that has the highest probability of success. We believe that our world-class operating practices, technical project execution capabilities, strong track record of working collaboratively with stakeholders, and strong balance sheet positions us well for future success. I thought I would just spend a little bit of time talking about what our priorities are in the near term. The first is to ensure that our assets continue to operate safely and reliably every day. Pipelines continue to be the safest and most efficient method of transporting large volumes of natural gas and crude oil. TransCanada's safety record remains among the best in the world, but we recognize that that is not good enough. No safety incident is acceptable, and we will not be satisfied until we achieve our goal of zero incidents. It's for that reason that we invest approximately CAD 1 billion each year on pipeline integrity and facility maintenance and why we continue to be industry leaders when it comes to supporting R&D to improve the safety and efficiency of our industry. Second, we are focused on improving the profitability of our existing assets by maximizing revenues and reducing costs in each of our businesses. Third, as Russ talked about in his remarks, we are focused on placing CAD 13 billion of small to medium-sized projects in service on time and on budget by the end of 2018. Fourth, we will continue to advance our CAD 35 billion of longer-term large-scale projects through the regulatory and permitting process in a cost-effective manner. Finally, we will cultivate a portfolio of low-risk growth opportunities in our three core businesses and core geographies. This next slide highlights a bit of our progress on those priorities over the past year. Despite a challenging and uncertain environment, our base business continues to perform well, meeting our safety and reliability targets and delivering solid financial results. In addition, we continue to advance our unprecedented capital program and position ourselves for future growth. Today, as we speak, approximately CAD 6 billion of new assets are under construction. They include expansions of our NGTL System, two new Mexican natural gas pipelines, liquid pipeline expansions in Alberta and the Gulf Coast, and a large gas-fired power plant in Ontario. We also added about CAD 2.3 billion in new small to medium-sized projects in our commercially secured portfolio of growth opportunities in the past year. Those include new NGTL facilities planned for 2018, expansions of our U.S. natural gas pipeline network related primarily to moving incremental volumes on ANR, the recently awarded Tuxpan-Tula Pipeline in Mexico, which is expected to be in service in 2017, and the Ironwood Power Plant acquisition, which should close in early 2016. Turning to our longer-term, larger-scale projects, although the recent setback on Keystone XL was disappointing, we have continued to make progress on our other three initiatives. In August, we reached an agreement with the Eastern Gas LDCs on Energy East and the Eastern Mainline project that resolves their issues. Just recently, we announced our decision to remove a port in Quebec from the scope of Energy East. Amendments to that project are expected to be submitted to the National Energy Board in Q4 of this year. In the interim, the NEB has continued to process our application, which was filed in October of 2014. We also continue to advance our West Coast LNG projects with the receipt of all the required permits for our Prince Rupert Gas Transmission project. On Coastal GasLink, we have received eight of the 10 pipeline and facilities permits required by the BC Oil and Gas Commission, and we anticipate receiving the final two permits before the end of this year. At the same time, we continued with our stakeholder engagement efforts and signed project agreements with a number of First Nation groups along both routes. We also continue to advance numerous other growth opportunities, including the potential refurbishment of Bruce Power Units 3 through 8, further NGTL expansions, and a number of incremental development opportunities in Mexico. Each of Karl, Paul, and Bill are going to follow with a more detailed review of our progress on each of these fronts over the rest of the morning. Finally, as Russ referred to, we recently commenced a very significant restructuring initiative to reduce costs and improve performance throughout our organization. I have a few more comments on that in a couple of slides. Further evidence of our progress, I think, can be seen on this slide. Despite the incredibly challenging macro environment, our diverse suite of high-quality, long-life energy infrastructure assets has performed extremely well. For the nine months ended September 30th, we reported comparable EBITDA of CAD 4.4 billion, an increase of 10% over the same period last year. Funds From Operations were CAD 3.4 billion, an increase of 9% over last year, and comparable earnings per share and dividends declared were also up 8%. The resiliency of our underlying asset base is a reflection of our disciplined approach to developing low-risk, long-life assets that are underpinned by cost-of-service regulation or long-term contracts with creditworthy counterparties. In 2015, our CAD 66 billion asset base is expected to generate approximately CAD 5.8 billion in EBITDA and approximately 90% of that is derived from regulated or long-term contracted assets. If you take a look at the pie chart, you can see that 40% comes from Canadian cost-of-service natural gas pipelines, 20% comes from regulated U.S. natural gas pipelines and Mexican gas pipelines that are underpinned by 25-year take-or-pay contracts. 20% comes from our liquids pipeline business, which is largely underpinned by 15-year or longer take-or-pay contracts. 20% comes from energy, with more than half of that coming from 20-year power purchase agreements with solid counterparties like the Ontario government and Hydro-Québec. The strength of that underlying cash flow, combined with the scale and scope of our North American asset footprint, puts us in the enviable position of being able to take advantage of the significant opportunities that are expected to unfold in our core businesses and geographies. As highlighted on this slide, today we are advancing approximately CAD 13 billion of small to medium-sized projects that are all poised to enter service by 2018. The vast majority of these projects are underpinned by long-term contracts. A regulated cost-of-service business model, which gives us a high degree of visibility to future EBITDA and cash flow growth. Our portfolio includes significant extensions of our NGTL System, three new gas pipelines in Mexico, the Houston Lateral and Terminal facilities, which will extend the reach of Keystone in the Gulf Coast, two regional Alberta liquids pipelines, Northern Courier and Grand Rapids, and two power generation facilities, Ironwood, which we recently agreed to purchase, and Napanee, which is a new 900 MW gas-fired power plant being built in Eastern Ontario. Turning for a minute to our CAD 35 billion of large-scale projects, these would clearly be transformational and would establish us as leaders in our three core businesses. They include the CAD 12 billion Energy Project, the CAD 8 billion Keystone XL crude oil pipeline projects on the oil side. Together, they would provide us with two million barrels a day of long-haul capacity and establish us as leaders in the transportation of crude oil from the WCSB to the most attractive refining markets in North America. Energy East would also give our customers access to new international markets, allowing them to maximize the value of their product. On the natural gas side, the Prince Rupert Gas Transmission and Coastal GasLink projects would see us invest approximately CAD 10 billion. Combined, these projects would be capable of moving more than four Bcf a day of Canadian natural gas to international markets, again, making us North American leaders in the transportation of natural gas for LNG export. All of these projects are underpinned by long-term contracts of 20 years or more, and together they would generate approximately CAD 4 billion of EBITDA on an annual basis. That being said, we recognize the growing social and political challenges that we face as a large-scale energy infrastructure developer. We really have learned from the Keystone XL experience, and while Keystone and projects like it remain critical to serving North America's future energy needs, we will only advance them if we can minimize the risks our shareholders experience in the event they don't proceed. That's why we structured projects like Energy East, PRGT, and Coastal GasLink differently than Keystone XL. Using the West Coast LNG projects as an example, if they do not proceed, we will recover the approximately CAD 300 million that we have spent securing regulatory permits for each project from our customers. If they do proceed, they will provide our shareholders with significant long-term upside. Looking forward, we believe the long-term fundamentals will continue to create tremendous opportunities to connect growing natural gas and crude oil supplies to market and replace aging infrastructure as North America shifts to a less carbon-intense energy mix. The scale and scope of our asset footprint, along with our technical expertise, financial strength, and approach to responsible development, are real competitive advantages. In our natural gas pipeline business, there will be opportunities to connect Western Canadian, Marcellus, and Utica shale gas to existing North American markets, as well as to LNG export terminals. There will also be significant opportunities to expand Mexico's natural gas pipeline infrastructure. On the liquid side, infrastructure is going to be required to connect growing WCSB and U.S. shale oil supply to key refining markets in the U.S. Gulf Coast and in Eastern Canada and give North American producers access to new international markets. In power, the growing demand for electricity and the move towards a less carbon-intensive energy mix will provide opportunities for new infrastructure in Alberta, Ontario, and the Northeastern U.S. Before I conclude, I thought I would just talk for a couple of minutes on the corporate reorganization that Russ referred to and that we initiated recently. Just in a nutshell, it is aimed at maximizing the effectiveness of our existing operations and reducing costs. As part of our plan, we are migrating away from a decentralized operating model to one where the individual business units are going to be given more decision-making authority and direct control over their costs and resourcing requirements. To ensure that critical standards are set for the business units and to take advantage of economies of scale, we will maintain certain corporate functions in the center, and we are creating a new technical project and systems center of excellence. Ultimately, we believe that the changes we make are going to directly benefit our shareholders and customers and improve our competitiveness. The changes commenced in Q4 of this year, and they're going to continue into 2016. As we advance our plans, we will be in a better position to provide you with more details. I thought I would end off with this slide, what it does, it highlights our outlook for growth from the CAD 13 billion of small to medium-sized projects that you heard me talk about that we expect to enter service by 2018. Once complete, these assets are expected to generate incremental EBITDA of approximately CAD 1.4 billion annually. That includes CAD 300 million from NGTL and Canadian mainline expansions, net of the impact that depreciation will have on rate base and EBITDA. Another CAD 375 million will come from the three new Mexican pipelines, Topolobampo, Mazatlán, and Tuxpan-Tula. U.S. Natural Gas Pipelines EBITDA is also expected to rise by approximately CAD 275 million, largely as a result of a growing contribution from ANR and improved performance at Great Lakes. Regional liquids pipeline expansions in Alberta and the Gulf Coast will contribute approximately CAD 200 million, and Napanee and Ironwood will collectively contribute about CAD 250 million. This growth, combined with solid financial performance from our base business, results in total EBITDA of approximately CAD 7.2 billion by 2018. That represents an average annual growth rate of 8% when compared to the CAD 5.8 billion we expect to generate in 2015. To be clear, this growth assumes no contribution from the four large projects. When any of those four projects proceed, they will drive this growth rate higher. Looking forward, as Don will highlight in his presentation, we'll also have the financial capacity to fund additional growth opportunities over the three-year period, whether they be one or more of those large-scale projects or additional small to medium-sized projects. Any new opportunities combined with the restructuring initiative we have underway should lead, in turn, to an average annual growth rate of more than 8%. I think that concludes my prepared remarks. If we have time, Dave, I think Russ and I'd be happy to take some questions. Thanks, everyone. Sorry. We certainly will make time for questions, as Alex highlighted. If any of you have a question, maybe just quickly raise your hand. We'll get a microphone to you so that everybody in the room, as well as those on the webcast, can hear. Andrew? Andrew Trevithick. A year ago, if you look at the last year, what's happened is your competitors across the street, they did a more Canadian-style drop-down into their affiliate vehicle. You've seen a pretty big de-rating of the GP MLPs in the U.S., among others, even some of the big. How do you look at the lay of the land now in the market, your corporate structure, and then any opportunities that may be on the horizon? Don will probably get into a little bit more details when he talks at the end, but I don't think our position has changed at all since last fall. We did an analysis of the suggestions that were made by others. The primary ones were dropping down on a larger scale to our MLP, as well as splitting off some of our power business. I think our view is unchanged, that we don't see value for our shareholders in doing that at the current time. We've always said that the rationale for having our MLP in place is to fund our growth at points in the cycle when we actually need the cash. Today, we don't need that as much as we thought. Our long-term projects have been pushed further out in the future. It's still an important source of capital, we'll go to those sources of capital that give us the lowest cost first. As Alex Pourbaix mentioned, our free cash flow, our debt capacity, our hybrid securities. We'll look at other asset sales potentially, as well as asset sales in the MLP to the extent that we need them. At the current time, that's not in our purview. We don't see that there's much value in accelerating those transactions if they don't add value to our shareholders. With respect to the other theme of splitting off power, I think that you can see the continued benefits of diversification across our businesses, being able to invest in power opportunities when they arise. Right now, there's a softness in certain of those markets. Not that many buyers, we're able to take advantage of that with things like our Ironwood acquisition, for example, which is obviously very accretive to us. We were able to pick that up at a six to seven times EBITDA multiple and tuck it into our portfolio in the Northeast U.S., which will give us the ability to continue to augment our dividend and growth on our dividend going forward. I think our position on those things remains. That's not to say that we won't continually look at them as our situation changes. If our capital program accelerates, we have access to those opportunities of both divesting ourselves of assets or of accelerating drop-down into our MLP. We'll continue to look at them, only to the extent that they add shareholder value. Are you seeing opportunities among the MLPs in the U.S. that have dramatically derated in the last few months? I do believe that on the horizon, there is the potential for quality assets to come available. I suspect quality assets will still attract reasonable prices. That said, we've seen this kind of opportunity recycle before. I've seen it two or three times in my career, where you have this kind of a meltdown going on, people becoming cash-constrained. For a company with an A-grade credit and financial capability, we can act on them and buy high-quality assets that wouldn't otherwise come available in a more robust financial environment. We'll continue to look for those and look for opportunities that are the best fit our portfolio. Thanks, Andrew. Sorry. Dean Rhonda, do you mind? Dean? Hi, it's Dean Highmore from Investors Group. This is a question for Russ. Similar to Andrew's question, last year, you were talking about an 8% annual dividend growth through 2017. As you mentioned also this morning, since that time, you've had some stalled projects and lower commodity prices. Given that backdrop, can you give us some more detail as to what has changed for you from a visibility perspective that gives you confidence now to project an annual 8%-10% dividend growth now out through 2020? I think there's obviously a few things that give us greater confidence today, is that CAD 13 billion of long-term projects, as Alex mentioned, I think have come to fruition. Things like Grand Rapids, we're actually moving on construction. Napanee, we're moving on construction. The 2 projects in Mexico are advancing. We're about 80% complete on those. We got pretty good clarity through to the end of 2018, at least. We've added about CAD 2 billion of new opportunities to that portfolio. Looking at the resilience of our base business through the downturn, as I mentioned in my remarks, we're at the worst sort of combined commodity cycle that I've seen in my career, yet our assets are performing exceedingly well. We're going to deliver record cash flows and EBITDA in 2015, despite those things. The resilience of our base business gives me a lot of confidence. I look at the reversal that we've been able to put in place on our natural gas business, for example. The headwinds that we had over the last couple of years on how would our Mainline fare in a world of growing Marcellus production. How would ANR fare? What we've been able to do is reverse the fortunes of those business. We now have a deal in place with our LDCs or with our shippers on our Mainline system that basically gives us comfort in the regulatory compact through 2030 for that system. On the ANR system, we signed 23-year contracts for the balance of the system, and it's just chock-a-block full, and people are looking for more capacity in their system. As I look across the system, everything's working well. The fundamentals are giving us a lot of confidence for a continued growth. The NGTL System, as I said, we just signed 2.7 billion cubic feet a day of contracts here in the last week. I don't think that's the end of it. Karl will talk a little bit more about that as we look to then move that 2.7 billion cubic feet a day to market somehow. That's just the receipt capacity. The transition from coal-fired generation to gas-fired generation or to renewables, again, we're starting to see opportunities arise on that front. In each of our businesses, I feel a lot more confident than last year. We have visibility. Don will actually talk a little bit about sort of the visibility of cash flows through 2025 and what that looks like to us. Again, focusing on those aspects of our business that are working give us confidence that at least through 2020, we can continue to raise the dividend at that kind of rate. Appreciate the question. Thanks. Linda? Linda Ezergailis, TD Securities. Russ, in the past, TransCanada has benefited from focusing on pipelines and power, and I know you do strategic periodic reviews, but have you looked at other potential platforms recently, like gathering and processing? I also realize historically there was a certain scale of individual assets that you focused on as well. Can you comment on any other platforms you've considered recently and what factors might need to be there for you to consider expanding the scope of what you do? I think if we look in the fairway of our three core businesses and our three core geographies, we see more than enough opportunity for us to reinvest approximately CAD 5 billion a year for as far as the eye can see. The reason for us to look at alternative platforms would be if we didn't see opportunity of that magnitude, and we'd have to look to other places to invest our capital for growth. As we look at those, as we had done in the past, they come with different risk profiles. You mentioned gas processing. We continue to look at that. We looked at it at the top of the cycle. We looked at it at the bottom of the cycle. Given the commodity exposure that comes with it's been something we've shied away from. We've shied away from gas-fired merchant power, for example, that doesn't come with capacity markets in some form or fashion. We would look at large-scale gas processing if it came with a contract similar to what we had historically. We had a very good straddle plant business here back in around the end of 1999, 2000, and that kind of timeframe. We sold off that business. We can see on the horizon that that kind of business might be available to us again if some of these LNG projects take off, for example. There's liquid-rich gas in the Montney. It wants to get itself to the West Coast to meet export spec. We've got to take the liquids out. To the extent that those providers, those producers, are looking for somebody to step in and operate that kind of infrastructure, we would do that. They talked about that as sort of the next step of their process. There's those kinds of things that sort of fit our low-risk business model that we would step into. At the current time, we don't see any need to sort of step outside of our risk band, if you will, of trying to be highly contracted or some form of regulatory underpinning. There are certain places where we'll tuck in commodity risk around the edges of our business. That's what it'll be, is it'll be sort of around the edges where we think we have a certain expertise to add value, and we'll keep it in a small portion. There will be opportunities, I think, arise to buy those kinds of assets in the coming months and years as the market has swung that direction. I don't think that'll be on our radar screen moving forward. Things that sort of fit our low-risk business model that we would step into. At the current time, we don't see any need to step outside of our risk band, if you will, of trying to be highly contracted or some form of regulatory underpinning. There are certain places where we'll tuck in commodity risk around the edges of our business. That's what it'll be, is it'll be around the edges where we think we have a certain expertise to add value, and we'll keep it in a small portion. There will be opportunities, I think, arise to buy those kinds of assets in the coming months and years as the market has swung that direction. I don't think that'll be on our radar screen moving forward. Things that sort of fit our low-risk business model that we would step into. At the current time, we don't see any need to step outside of our risk band, if you will, of trying to be highly contracted or some form of regulatory underpinning. There are certain places where we'll tuck in commodity risk around the edges of our business. That's what it'll be, is it'll be around the edges where we think we have a certain expertise to add value, and we'll keep it in a small portion. There will be opportunities, I think, arise to buy those kinds of assets in the coming months and years as the market has swung that direction. I don't think that'll be on our radar screen moving forward. Ralph Faddis with Real Growth Investment Council. I think the pipeline infrastructure is critically important to Canada. Any feedback from the Trudeau government, how they're going to view that now? I guess Energy East would be one. I think that it doesn't matter what government's in place. Resource development in Canada is extremely important. It's important to Alberta, but it's also important to the Canadian economy. I think as Alex mentioned, in order to make that happen, it has to be done responsibly. I think that the new government and the previous governments have all said that's a precondition. We need to work with them to understand what that precondition means. We are leaders, both as a company and as a country, in developing and building safe and reliable infrastructure and the regulatory oversight that comes with it. The new government is just getting started. We'll engage with them in the process. They've indicated that they want to review some of the standards. What we've indicated to them is that we're open to that as well. We all benefit by ensuring that we have the best possible standards. That ensures that we don't have incidents, but as Alex also pointed out, is there's a public confidence component that comes with that as well. We want to work with them in ensuring that we do whatever is necessary to make the public comfortable. As I get out and I talk to our customers and in our focus groups and community meetings and things like that, what we find is that people understand they need energy. They just want to know that it can be done safely and reliably. Once we get into having those conversations, they understand what we do. What we find is that, as Alex pointed out, we end up developing a long-term relationship with these folks. We have thousands and thousands of landowners that we deal with on an annual basis. This isn't new for us. We've been doing this for 60 years. We marry these people essentially when we go onto their property, and we want to develop that long-term relationship with them. There's a lot of rhetoric that goes on in the media and elsewhere. Down on the ground, when we actually engage with landowners, for the most part, we have tremendously successful relationships. That's what it's about. That's what we'll continue to do. I believe if we continue to do that, governments will be supportive of what we're trying to accomplish for our company, but also for the province, for Canada. Robert? Sorry, we'll just get you. Robert Kwan, RBC. You talked about, a little bit touched on the A credit rating, and it's had a good defensive measure as it relates to funding. At times in the cycle, it's allowed you, as you mentioned, to buy specific assets. You had a couple out of bankruptcy here. As you think about using that A rating, if we start to see more distress, what's the interest or the willingness to get into something that would be more complex, a corporate deal, particularly one, say, where you get a collection of assets, but maybe there might be some asset sales involved. Is there an interest in something that would be more complex, or do you want to keep it as specific assets? I don't think we would shy away from a corporate transaction that could add value to our shareholders. We're not frightened of managing asset sales through the process. We've done both over time. I think we've been very successful in being able to sell assets at different points in the cycle and trying to capture the best value that we can. I don't think we would shy away from anything of not extreme complexity that we can't make sense of, but anything that our shareholders can make sense of that's accretive to earnings and cash flow and gives us a platform for growth in the future, we'd certainly be interested in it. If that requires us to divest assets, both inside of our existing portfolio, but inside of an acquisition, we certainly wouldn't shy away from that. We have all the capability and expertise to do that. Russ, you mentioned the accretion on earnings and cash flow, just with jumping ahead, the disclosure of DCF? Can you talk about the relative importance of those two measures and specifically the importance of immediate accretion versus maybe taking a little bit of dilution upfront if it helps establish the strategic platform? On DCF, I will leave that one for Don at the end. Obviously, as I mentioned, we have strong dividend cash flow coverage ratios as we look at it from a distributable cash flow perspective. Again, I think that we're a leader on that front, and I think Don's going to potentially provide you some details around that here when we're done. What was your second question, Robert? Just in terms of the willingness to take dilution upfront, if you think it provides strong accretion and value and establishes a new strategic platform. I think theoretically, of course, we're willing to accept dilution upfront for something that provides strategic value in the long haul. As you can imagine, we have a group of business development folks that always make the case of take some upfront dilution and it'll provide backend value. If you're really careful about that word strategic, it can lead to a lot of bad decisions, I believe. If it truly does add value in the long haul, of course, we would do what best adds shareholder value for both the short and long term. I think if it's obvious, then our shareholders are going to see that obviousness of it and reward us for that. If they don't believe that that future value is really coming, then we're not going to get rewarded for it. I think that our focus is on making sure that we do things that make sense for our shareholders and are visible to them. I look at our portfolio today, we have got a lot of backend-loaded kind of opportunities. We are really seeking to augment growth in the short run. That is very important to us. If you look at things like the Ironwood acquisition, for example, it was a perfect fit. It was accretive to cash flow and earnings out of the gate. It fit the size of our portfolio in the PJM market, we were able to acquire it. That is the kind of thing we want to do, but as you know, theoretically, that is the perfect kind of fit. Everything is more complex than that when you actually get into it. We will not shy away from things that add long-term value, but Alex, myself, the executive team, we are always suspicious of that promise of things on the come. If it is not clearly contracted how you get there, we would probably be hesitant to move forward on it. We would not take, for example, a backend commodity risk in the hopes of prices rising or something like that. If it was clearly contractual opportunity, of course, we would look at something like that where you could clearly tell your shareholders we can see our path to accretion in one or two years. Okay. We will take just one more question, then we will move on with Carl. I think Stuart, just behind you there. It is Ben Pham, BMO Capital Markets. Just going back to your guidance extension to 2020, to talk more about the visibility question before. The 2020 timeframe coincides with a couple expiries in the power side, Alberta Power, Bruce Power. You may have some potential reinvestment in Ravenswood ultimately. You talked about some increased confidence in new projects going forward that is going to hit the hopper there. How do you guys get comfortable with the expiries coming up through the late decade as you think about your strategic plan to extend that guidance? I think you'll probably hear from Bill later today on You mentioned the power expiries. Obviously, we're looking at Alberta Power right now. It's not contributing a whole bunch to our EBITDA. As I said, in the bottom of the cycle, we're still delivering very substantial growth. Alberta is going to have to restructure itself. Bill is going to talk about that in the future. It's going to have to transition from a coal-based production base to something else, gas or renewables. We're well-positioned to take advantage of that. We'll continue to watch how we're going to extend Alberta. I would say that's core. Looking at Bruce, as mentioned, we continue to work through that deal. We think that Bruce is very critical to the energy mix here in the province of Ontario, and we will get through that deal. Obviously, don't take the fact that we're moving slow on it that it's not something that both parties want to do. I think it's clearly something that both parties want to do. As I look out to 2020, I look at the growth in our base cash flows from all of our businesses, as I said. The opportunity for new growth that comes from those kinds of things is any way that we looked at our financial modeling, there wasn't a scenario that we felt uncomfortable with providing that kind of guidance through 2020. Whether we're sort of low end of the growth in adding new projects or the high end, we felt totally fine. As I said, the question I had earlier on versus where we were last year, a whole host of things have changed quite considerably. As I look at the growth in North American gas is I think folks keep thinking that at low prices, we're going to see less production. In fact, we're seeing folks drive down the cost curves both in Marcellus and in the Montney. We're seeing people being able to produce gas for $1.50 to $2 in MCF and actually make money. Not everybody makes money, but a good chunk of them are making money at those kind of levels, which means that that gas has got to get to market. I look at where we're situated on top of both of those basins We're looking pretty good out to the end of the decade. As Don will talk about later, I think we're looking pretty good beyond the end of the decade as well. Sorry, Ben, just further to that, as Russ highlighted earlier, Don's going to get into sort of the longevity, if you will, of the cash flows right through to 2025. I just highlight that for folks in the room. We do intend to dig deeper as part of Don's presentation. Sorry. With that, we'll turn the podium over to Karl Johannson. Karl is President of our Natural Gas Pipeline business. He'll offer a few comments on that business and then be happy to take your questions. All right. Thanks, David, and good morning, everybody. It's good to be back here again to talk about the gas pipeline business. The gas pipeline business has had a very good year. It's on track for record performance this year. Both this applies to virtually all the assets that we have from Canada, NGTL, the Mainline, ANR, GTN, the LP, and Mexico. It's been a very good year for the gas pipelines. The stability and predictability of our base gas pipeline business cannot be overemphasized. Our rate-regulated pipelines and our contracted pipelines are both equally working very well right now. We are well-positioned in our core geographies as well. Across Canada, the U.S., and Mexico, many of you will have seen our press release last week on the New Mexico project. We're still seeing some growth in Mexico as well. Our long-life pipeline assets and long-term commercial arrangements are the cornerstones of this low-risk business model in gas pipelines, generating substantial cash flow and earnings on this portfolio. The vast majority of our gas pipelines are regulated or at some sort of cost-of-service or take-or-pay arrangement or long-term contract that supports the long-term nature and sustainable cash flows of these assets. As you can see on the graph, I actually advanced the graph, and I shouldn't have. Go back. Just talk a little bit about the steady and growing EBITDA on it. Since 2011, 2010, we've seen EBITDA grow from about CAD 2.9 billion, on track this year to be about CAD 3.4 billion. I'll talk a little bit about what we see in the future going forward. As you can imagine, this footprint that we have for our natural gas pipelines is really well-positioned to show some ongoing growth coming in the future, and I'll talk about that in a minute. I've shown this slide before on our strategy, and I think it's just as relevant as today as the first time I showed it probably a couple of years ago. I think the important part of this slide is to take a look at that box, the insert there, and Russ showed this when he was talking a little bit about the growth of supply and demand in this business. When you take a look at that growth, you begin to realize that over the next 15 years, we're going to see about a 50% increase in gas demand and supply in this business. The fact is, the new technologies, the impact they've had on price, the impact they've had on being able to deliver quantities of gas are working to see gas demand increase. We see it every day in our systems, from industrials, from people looking for more LNG, for more power conversions, from coal-to-gas conversions or just more power. We see it every day in our business, and we're quite confident that a forecast like this over the next 15 years is going to come to fruition. What does that mean for the strategy of our pipelines? Well, that means our strategy has not changed much. It's still twofold. Number one, we have to make sure that our existing position remains competitive. We have to make sure that within that existing footprint that we have, that we maintain preeminent positions in our areas and we capture the gas demand and supply as it comes forward. It also means we have to take our footprint, and we have to make sure that we make targeted investments throughout our network that can continue to get our fair share of the new business coming in this market. If you think of it, over the next 15 years, a 50% increase in activity in this region, there's going to be gas there needs to be transported. Right now, we see it every day. The surplus of gas that we're seeing brought onto the market, the excess gas that is causing the actual price decreases needs a place to move, and it's moving on our pipeline system. We are getting our fair share of that business. We also continue to advance our MLPs drop-down strategy. We just announced the sale of 49.9% of our interest in the Portland Gas System to TC Pipelines. Our settlement with the Eastern LDC supports the Energy's regulatory hearing and will assist us in moving forward with this important Canadian initiative. We also intend to capture the full future growth opportunities, whether they be related to new demand, the expansion of existing networks, or even repurposing some of our pipelines from gas to oil. With respect to potential for LNG exports in North America, we are well-positioned. As you can see on this map, we are positioned for both the West Coast, which I'm going to talk about some of our projects there, where we are actually moving gas into the Gulf Coast for our future LNG delivery, and we're actually getting lots of interest on the East Coast as well for moving gas to the East Coast for LNG delivery. This network allows us to go from coast to coast to coast, literally. To get into our existing businesses here, I want to talk a little bit about NGTL's business. As you know, over the past few years, the resource potential in WCSB has dramatically increased as a result of new production technologies. The resource base has more than tripled, and almost all of this increase is attributable to the shale gas that you see in that shaded area there. This is the Montney Duvernay, Deep Basin, Horn River, Liard, and Cordova areas. As you can see on this graph, you can see our NGTL system overlays this area perfectly. In order to connect the growing production coming from these emerging shale plays, new infrastructure will be required. As you can see again, the new infrastructure is starting to come in our system because of its great proximity and the ability for our system to actually handle these volumes. When you take a look at the volume shift in the WCSB, it's moving towards the shale play almost exclusively, and these customers need large-scale pipeline infrastructures. They need pipelines that can deliver markets to them in order to interconnect things. That's why NGTL is getting more than its fair share of business out of these because we have the ability to move the gas. We have the markets on our system to move it. Today, the NGTL system gathers approximately 75% of WCSB production. It provides shippers with significant optionality and liquidity. We moved over 10 Bcf of physical gas in 2014. This year, it looks like we're on track for about 11 Bcf a day of natural gas. We have deep markets on this system. The net hub alone, the Nova Inventory Transfer Hub alone, probably still trades around the 60 billion cubic feet a day of financial products on this. Deep markets for producers that want to get their gas on and get it sold. We also have several export opportunities from this. When you put your gas on our NGTL system, you can send it on the West Coast, you can still send it to Eastern Canada, you can send it to the U.S. Midwest. We have a local market in Alberta on the Nova system that is bigger, almost twice the size of Eastern Canada, for example. It peaks at about 6.5 Bcf a day and growing. That's a significant market for people producing natural gas in our system. I would say that in conjunction with that, we are virtually the exclusive supplier of natural gas into the oil sands. As the oil sands gets built up and continues to grow, we'll keep seeing the additional market on our system for that purpose as well. I want to talk a little bit about the growth. I think last year we came here. We just announced about a CAD 2.7 billion incremental growth on this system. We've announced other incremental growth like the North Montney, which is CAD 1.7 billion. North Montney obviously will go ahead when the Prince Rupert project goes ahead. Certainly the CAD 2.7 billion 4 Bcf a day expansion that we announced last year is moving ahead as planned. I get lots of questions. Is there being a delay? Is anything being delayed because of the price input? The answer is categorically no. We've moved some smaller projects around, but we're on track to continue and getting permits for the full CAD 2.7 billion worth of growth in NGTL. The gas is coming to us. The gas is economic to produce. It is coming onto the system. We are working as hard as we can to make sure that capacity gets on the system. For any of you that have followed the struggles that some of the producers have had trying to get firm capacity on our system, you'll see why. Right now on our system, there's virtually no interruptible capacity left. You cannot move gas on our system on an average day right now unless you have firm transportation. That's just a sign of the amount of gas that's coming to us. That expansion is going full ahead. As a matter of fact, you'll see that we just announced there so go another expansion number coming up for 2018 now, about CAD 600 million, about 2.7 billion cubic feet of expansion. That's exhibited on the graph on the right-hand side here. Just to talk a little bit about that expansion, it's mostly receipt expansion, mostly new production coming on our system, and it's mostly interconnection of receipt supplies on our system. As I think Russ said earlier, what you can expect in the future here, very near future, as we're sitting down with our customers and asking them where that 2.7 billion cubic feet a day is going to go. Once we determine where the markets are on that, hopefully, we'll see if we need to do a downstream expansion to facilitate the markets on that as well. All this work that we're doing on this is going to move the rate base of NGTL from about CAD 6.2 billion in 2014 to about CAD 11.2 billion in 2018. Very significant build-out of the system, and the build-out is all happening along that ferry that you saw on the previous slide where the shale gas is located. The NGTL system is essentially fully contracted to date and has been operating really at capacity for the last year and a half. As you can see every year, you can see demand for new NGTL facilities, and we expect the trend to continue. With the growing supply source and increasing interbasin demand, along with the potential for future supply-rated infrastructure development for the LNG industry, ongoing organic growth opportunities in this particular business unit remain very attractive. We do intend to continue leveraging NGTL's unparalleled footprint and market position to continue to be the preferred supplier in this region, and I think we can expect more good news coming out of this asset coming into the future. I want to spend a little bit of time on the Canadian Mainline. This is something that we've talked a lot about lately, and I think Russ and Alex both touched on where it was and where it is today. I guess I can say a couple things about it right now. The LDC settlement that really was effective January 1, 2015, really has set this particular asset up to be a very valuable asset for us for at least the next 15 years of the term of that settlement. That settlement really has several Agreements within it, some expiring 2020, but really the main part of that agreement is that there will be no bypasses of any kind of our system until 2030. We feel that we've got a system and a commercial agreement with our shippers that's really going to last the next 15 years. What does that mean for the Mainline? Well, what that means for the Mainline is going forward, that we're going to have two systems, essentially, ultimately. One's going to be the Western system, one's going to be the Eastern system. The Eastern triangle on this system is chocker block full. It is people, in order to get onto the system now, you have to enter an open season with us, and you have to sign a 15-year contract to get any additional capacity on that system. That system is in the heart of the population of Ontario and Quebec. We do not see any ability for people to get around us on that system. They're going to have to use the TransCanada system in order to get their supply. We're quite comfortable in the long-term future of that triangle. The Western system, we're quite comfortable as well. As you can see on this chart, by the time the settlement takes impact, which is really 2020, the financial part of the settlement, we'll only have about CAD 1 billion left in the Western system. We have indigenous demand along the Western system. The Western system is still a conduit to get to Emerson. It's still a conduit to get to Midwest U.S., and it's still a conduit to get to Dawn and the Ontario markets as well. There's going to be plenty of opportunity for us to recover our capital, that last CAD 1 billion on the Western part of the Mainline system in and of itself. We believe that we will be competitive. We believe that gas will flow on it, and we believe enough gas will flow on it to recover our capital there. We just don't see anything on the horizon that would prevent that. Even in the case, for example, let's say Energy East gets delayed or even if it doesn't go, the capital Energy East has taken out of that, the actual CAD capital, that Western system is very small. Most of the CAD capital that Energy East has taken out really comes out of the Eastern triangle. By the time you hit 2020, there is not very much capital left in the Western system, regardless of Energy East pipeline transfers. Just some other information on it. Total volumes on this system today. Traditionally, we've talked about what is our Western receipts, what's moving long haul through the pipeline. That today is still about 3 Bcf, 3.5 Bcf. The real important statistic on that, and you'll see in our documents over time, we're starting to move what the relevance of that number is. As I do my expansions on the Eastern triangle and bring in more Marcellus, that Western receipt will fall. The important figure on this pipeline is what is our total contracts? What is our total throughput on the pipeline, which still remains about 7.5 Bcf a day. If you take a look on this, regardless of where it comes in, if it comes in from Dawn, comes in from the West, we're moving 7.5 Bcf a day on that pipeline. That makes it one of the biggest pipeline systems actually on the continent for natural gas. It's got a robust contract base and it's got robust flows on it. The issue is the locations where those flows are changing, and we've taken care of that financially with the LDC settlement. The bottom line is we believe that the Mainline has demonstrated its resiliency as a critical gas transportation system and is positioned very well for the future. Just to give you another idea on the Mainline, this year, we're going to recover about 50% more revenue than we did in 2012 and 2013. If you think of where this asset has gone, vis-à-vis 2012 and 2013, we're now collecting about 50% more revenue. Obviously, we're over-collecting right now, and we're going to have to refund some of that over in 2017 or next year to our customers. It's better to be in a position right now where we're over-collecting a little bit than where we were maybe in 2012 and 2013 when we were under-collecting. Really, that asset, we don't have any concern going in the future as to the viability and the need for that asset. Just to talk a little bit about the growth. We're deep bottlenecking it in two places. Number 1 is on the southwest corner of the triangle. We're going to be putting about CAD 400 million of capital in. That'll allow more volumes to come in from the Marcellus if our customers choose to bring it in from the Marcellus. That work is in various stages of permitting and ongoing right now. We also have the CAD 2 billion Eastern Mainline project, which really runs along that Montreal Corridor, as we call it, from the southwest corner to Ottawa. That way, we will be building as Energy East progresses. We will be building that as somewhat of a replacement for the capacity we're taking on for Energy East. That's strategically located. This particular corridor will actually increase our ability to bring in more Marcellus and Utica gas into our system, it'll stiffen up our system. That'll be about 700 million cubic feet a day on that one. Talk a little bit about the U.S. gas pipelines. The remaining long-term contracts underpinning ANR's increased transportation commitments started this year in early November. Those lines are now all flowing on our system. Looking at this map, you can see that we are positioned in pretty good key areas in the continent with multiple bases and multiple demand areas. The lighter pipelines on this map are the ones that are held 100% by the LP, TC PipeLines, LP, while the bolder ones still are either 100% or partially owned by TransCanada Corp. Our U.S. assets have delivered solid results in 2015, with EBITDA generated from these pipelines increasing about 5% year-over-year. We expect to invest approximately $500 in these pipelines. Most of this is ANR. Over the next three years in new capital, really to get our capacity back up to where it's historically been. We're now full on that system, we have to put some dollars into it to make sure we have the capacity there. Many years, we ran this pipeline system at under capacity, you just didn't need to maintain that capacity. Now we're investing more dollars into it. Not only was we invested CAD 500 million, but we have ongoing maintenance programs that'll bring more capital in the system. We are looking at our system right now. We're looking at the returns we're getting with the new capital. Although we have a target of CAD 300 million EBITDA on this, which I think we will ultimately get to, although right now we're spending a lot of extra capital getting capacity up. If we do not get the return that we feel is adequate given the amount of capital we're putting into it, we will enter into discussions with our customers and potentially go forward with the rate case, if needed, to get that capital. We're quite pleased with the investment we're making in the pipeline right now, we expect we'll see good returns from it in the future. The remaining U.S. gas pipeline assets are expected to generate about CAD 420 million EBITDA in 2016. ANR's role to be in probably the majority of that, about CAD 300. I think Russ touched a little bit on this. I think Don will talk a little bit about it earlier. Our sponsored MLP, the TC PipeLines MLP, is an important part of our U.S. pipeline group as it owns or has interest in six, and soon to be seven, FERC-regulated pipelines. It has a strong balance sheet, an investment-grade credit rating, and the LP is a solid financial position in place for growth for future drop-downs and other transactions that we might see fit to put into that. Looking forward, it is supposed to play a critical role, I think still, in the financing. As Russ said, there is always the caveat on this that it has got to be good for TransCanada Pipeline shareholders, TransCanada Corporation shareholders, but it is a good vehicle. It is healthy. It has got investment-grade credit rating, and we can use that in the future for financing if we need it. We have a pretty constant drop-down strategy right now into it as well. Talk a little bit about Mexico. Many of you saw, I talked to many of you last night, just our latest announcement in Mexico, the Tuxpan Tula, which is really a little bit south of Mexico there on the map, as you can see it. That brings the total amount of pipelines, significant pipeline business we have in Mexico to about five pipelines. A little more than $3 billion U.S. invested in there. We are still very excited about the Mexico opportunities. The CFE alone right now still has five more, what I would consider large pipeline systems to be RFP'd or put off a competitive bid over the next couple of months. Literally by February, they will have these five put out. There is other business in Mexico, too, that we have not even touched on. There is business and we have been looking at the power space. We always look at the liquid space, but there is more gas business as well. Right now we are fully engaged with the CFE's efforts, but as the CFE's efforts start to scale down, which ultimately they will, we still have other business there that we can pick up on. We are particularly excited about Tuxpan Tula. That pipeline goes right through the industrial heartland of Mexico City. Not only do we have the CFE contract for 25 years as usual, we actually have lots of what we consider lots of ongoing business to be done with that pipeline. That industrial area right now is burning fuel as we speak. They are just not burning natural gas. Or if they are burning natural gas, they are not getting enough of it. We will have some work ahead of us just to make sure other major industrials get access to our pipeline system in. Our business right now is going very good there. We have two pipelines under construction, as Russ said, they are about 80% complete, Topolobampo and Mazatlán pipelines. We are expecting them, the third and fourth quarter, to come on stream, and we will be starting the construction Tuxpan Tula here real quick. As you can see from this map, we have got still lots of work to do, and we are quite excited about our position in Mexico. As you can see, most of the new bids, at least the first three, are all in the Mexico City area where we have, I think, we have our strongest position in the country. We talked a little bit about the West Coast LNG as well. I do not know what else I could add under this. We are pretty much ready and waiting here. On the Prince Rupert, the PETRONAS project, we have all of our permits as a pipeline. PETRONAS is waiting for their last environmental assessment permit from the federal government. We are right now working on Aboriginal agreements. We're getting good progress on the Aboriginal agreements on that line. Of the 20 Aboriginal groups there, I think we have nine agreements right now and many more under negotiation. Not that you even need these agreements to be able to proceed. We have to consult with the Aboriginal communities, but these agreements do show that there is a significant amount of Aboriginal support for these projects. Coastal GasLink is our Shell-sponsored LNG project going into Kitimat. We have eight of the 10 permits. We're expecting the last two permits to come before the end of the year. We have about eight Aboriginal agreements out of 19 Aboriginal groups along our pipeline. We've gotten good support from the Aboriginal groups. Our proponent, Shell, has got all their permits they need, and we're just waiting for an FID for them. Both of these projects, I think, are well-positioned, both with our physical work and our permitting, and we're just waiting for our customers to give us positive FIDs on it. Looking out to 2018, we showed the contribution of all CAD 8 billion in commercial secure gas pipeline projects that we currently have under development. This includes our Canadian regulated pipeline projects for NGTL in the mainline and our Mexico projects. I also note that our outlook only goes to 2018, other commercially secured projects like the LNG pipelines or the Merrick NGTL expansion are not included in this analysis. The chart on the right not only shows that our pipeline business is expected to be substantially larger by 2018, it also depicts the EBITDA contribution of a much more diverse portfolio in the future, all of which are long-term commitments and are underpinned by regulated or cost-of-service business models. EBITDA is forecast to go from CAD 3.4 billion in 2015 to CAD 4.3 billion in 2018, which equates to a compound average of about 9%. Just to wrap it up on key takeaways, I'd like to again emphasize the stability and resiliency of our pipeline gas business and the commercial models underpinning it. Our assets are located in close proximity to North America's growing shale reserves and are being able to adapt to the commercial environment that they're in. We have approximately CAD 8 billion in commercially secured projects that are in development that will lead to significant EBITDA growth over the next three years, and our longer-term pipeline projects have the potential to contribute even further to that. Our MLP drop-down strategy is advancing. I believe our recent action to sell 49.9% interest in the Portland Natural Gas Transmission System is testament to our continued commitment to the TC PipeLines, LP. Finally, our existing footprint of essential gas pipeline infrastructure is proven to be extremely valuable and enable us to capture future growth opportunities across the entire continent, in Canada, the U.S., and Mexico, and we expect to continue to do this. The high volumes that we're seeing, the high production that we're seeing, needs transportation, and we are in a good position to provide that transportation. That's all for my prepared notes. I think we can have a few minutes for questions if people want to ask questions. Certainly time for questions. Again, just raise your hands to the extent you have a question. We'll get a mic to you. Question? Hello, Rob Pope with Macquarie Capital Markets. Just in terms of your Eastern strategy, you do move quite a bit of Marcellus gas on your Eastern triangle. However, you do not have any pipelines in the heart of the Utica or the Marcellus. Do you have any strategic plans to enter that play at some point? Well, I completely agree. I think when you look at the Marcellus, we've been able to get it because it's just grown so big, it's come to our pipelines. We are always looking for new ways to extend our pipelines into the Marcellus. I have to tell you, we're in a pretty good position now. We're happy where we are, but we would like to get a pipeline into there. It's not as easy. We're not really an incumbent into the heart of Marcellus right now, it's easier to build it if you're an incumbent. We're actually in a good position that we've managed to get. We actually have the important part of the pipeline, which is getting down to the Gulf Coast or getting up to Dawn or getting west into the Chicago area. We're expecting to keep attracting more volumes because we have the long-haul capacity to move the Marcellus. Certainly, I would prefer to get a pipeline right into the heart of that myself. I have to be realistic. There are incumbents there that can do that probably cheaper than us, and that can gather up the gas probably in a more efficient, quicker way than us. That's what we've seen up to now. Other people have been bringing that gas to us, and we've been moving it to markets. I suspect that's probably going to be the main part of our business. If I can't figure out how to get a pipeline in there, either through greenfield or maybe even a little acquisition or something like that would be a great thing for us to work on. I don't think it's necessary to continue to fulfill our strategy of moving that gas into market. All right. Thank you. One quick follow-up. You did mention the potential to feed East Coast LNG terminals. Yes. Do we see some larger diameter pipelines to East Coast ports? Well, it's a good question. There are several proposed East Coast LNG in the Canadian Maritimes right now. The work we've been doing so far, I just don't think they're ready now for an expansion of our mainline right to Halifax or anything like that. What we've been working on is getting them transportation, maybe the last year from Dawn through PNGTS down and then up the existing infrastructure, which they will ultimately reverse and they have me going up there. You're right, there are several alternatives they could have. There are some pipeline projects that are contemplated in the New England area, and maybe they could use that. I think we have the only opportunity for them where there's pipe in the ground right now that they can go from the mainline on the PNGTS, the Portland Natural Gas Transmission System, and then up the Maritimes & Northeast Pipeline to get to their facilities. If there's going to be very large-scale East Coast LNG, I think they're going to have to look at other options, too. There's just a certain amount of capacity that can get through that type of route as well. Sorry, Linda. I have a follow-up question with respect to NGTL. You've had a lot of success getting receipts added, and you mentioned that there might be some need to think about deliveries and maybe expanding the core part of the system. Can you talk about the bookends of what sort of capital might be needed for that? We'll be able to ascertain this probably in the next three months or so. We're just talking to our customers. Realistically, there's going to have to be some work. For 2.7 billion cubic feet a day of new supply, there's going to have to be some work done on the trunk part of our system. The bookends, I would loosely say the bookends probably from an equivalent amount, maybe another 500 million to twice that, depending upon where people want to go and what capacity we have to take into those markets. That's probably where we'll ultimately look in, but I'm quite certain that we'll need to do some work and you can't in that area, working on the big-inch pipe there, we're going to have to probably at least do equal amount for the trunk. It could even get bigger if they all want to go in the same spot, for example. Just to follow up on NGTL. In terms of counterparty risk, you've got smaller and smaller players that historically would count on interruptible service now needing to sign up for firm. Can you comment on how you're managing that? Well, the counterparty risk, we have regulated terms for credit, as long as we follow our regulated terms, I assume we'd be deemed prudent in case we ever had a credit incident. The terms are, all meant that the system is being set up to encourage people to get on the system. The credit terms aren't what I would consider overly onerous for people to get onto the system. I do believe our work here at NGTL is to make sure that we follow the regulatory policy as put out, if we do have a credit incident, then we would expect the system to compensate us for that. Really, we have to understand that system's really been set up so that people can access it on a credit-friendly basis, I would expect the board to uphold those credit terms on that. I would point out that we're getting longer and longer contracts from people right now, typically eight-year contract. Some of these LNG-related contracts go out even as far as 20 years on that. We're getting more credit term, but more term in our NGTL contracts. For the credit, we watch it quite closely. We want to make sure we're compliant with our regulatory statutory requirements to collect credit. Next. Steven? Steven Paget. Steven Paget, FirstEnergy. Karl, I believe Alex talked about better EBITDA out of Great Lakes and what might drive that. A couple of things happening with Great Lakes. Number one, we finally got a FERC ruling on the TBO arrangement between Great Lakes and ANR, which you saw in this last quarter added quite a lot to the Great Lakes income. What happens is ANR needs Great Lakes to access its storage. ANR is actually the largest customer of Great Lakes. We're actually expecting, as we get more of this capacity on the system on NGTL, we're actually expecting better utilization out to Emerson and then down Great Lakes. We think that's the most logical incremental market for that 2.7 Bcf of gas that's going to come on. We are looking for Great Lakes to get better. We have to be frank, though. It's never going to be where it was many years ago, right? It's just going to marginally get better. I also think when you take a look at ANR, when you see us putting in the capital, the CAD 500 million of extra capital to get back to our capacity and the ongoing maintenance capital that we just have to put in now to maintain that capacity, you're going to see more revenue coming out of there. We may be able to get more revenue right now from different services we sell on it, or we might have to go back to our shippers and start negotiating because what will happen as we put that capacity in is our return on equity will start going down until we actually get another revenue stream. When you look at that, I think that was in Alex's slide. That's a combination of those two things you'll see in the future. In one way or shape or form, either we'll have a negotiation with our shippers or ultimately, I guess, a rate case if we couldn't come to agreement with our shippers. Thank you. A second question, if I could. Could TransCanada's current restructuring and savings result in higher mainline ROE in the future? Well, for our Canadian regulated pipes, we generally are on incentive programs. You've seen on the mainline the last couple of years, we've actually done very well on our incentive programs. I would suggest probably we're going to do pretty well again next year on our incentive program. I guess short answer to that is yes. As we reduce our costs, our costs are part of that incentive program. We have net revenue requirements, and if we beat them, we share in those. I would suggest that as we reduce our costs, we will share in that because we'll be under our net revenue requirements. How much that is, it's just tough to say right now. If you recall, our incentive-sharing mechanism is we get the first CAD 27 million, it's 100% ours. The next CAD 40 million we get 25% of, and anything over that we get 10% of, to a maximum 11.5 ROE. If we're in the 10% collar right there, we get 10% of it. If we're actually not earning extra revenue through our discretionary sales right now, we might actually get a bigger portion of it. It just depends where we are in the rest of our business as to how much we get. Okay. Matthew? Hey, Karl. Matthew Akman, Scotiabank. Hi, good morning. Question on NGTL. You guys have obviously done a great job and had a lot of success in the expansion of that system, you showed that rate base will not quite double, but expand dramatically in the next few years. That obviously gives rise to cost as well and earning the cost of that increase in capital, probably volumes won't grow as much as rate base overall. The capacity yet is extremely valuable, obviously, as customers are signing contracts. I'm just wondering what your volume expectations are in NGTL over the next three or four years, especially given quite depressed gas price and whether there are rate design issues that are associated with the expansion that you need to address, and what your general regulatory customer strategy is to make sure that customers that are benefiting the most from these big expansions are paying for it, and others aren't getting hurt. This is a good question, actually. It's one our regulator spends quite a lot of time on. We have a traditional rolled-in system on the NGTL system. It's not a postage stamp rate. We have a locationally differentiated rate, but it's a rolled-in system on the NGTL system. As you could tell with our latest ruling from the NEB on North Montney, the NEB's starting to question the roll-in and what's the incremental cost to other producers on the system. I can say this. I'm not going to give forecasts of volume going in the future, but we're expecting the volumes to grow. They grow to Bcf a day this year, and we're expecting a lot of this volume to come on to be incremental volume. Now, when I talk about that, I'm talking about FT volumes. You have to understand, some of the contracts we're getting right now are from people that used to be on interruptible transmission that can't get it anymore. They want to be FT. We got a little bit of that, where the volumes were already on our system, but they're getting shut out. They're buying as well, right? We are expecting increased volumes. What I can say, and this is part of our filings, is that we do expect that the cost to our shippers from both the last one last year and this one this year is, last year, we expected about CAD 0.01 per gigajoule cost for our shippers to bring in last year's incremental, and this year's will be somewhat slightly less. This year, we have more volumes with less dollars, it depends what the downstream bill comes in. You could say maybe CAD 0.01 on both particular expansion drives, which is still pretty reasonable when you look at what the FTR tolls are in the province. If our volumes, we put the capital in, if our volumes do start decreasing, obviously, that's where you get bigger price increases. What we're seeing right now is these volumes are coming on pretty much incrementally right now. When we talk to our customers, we are expecting more. They're getting great results in the regions that they are, that we're building in, and we don't expect these pipes in these regions to go underutilized. We are seeing a shift from the production that was in Central Alberta and Eastern Alberta over to the Northwest Alberta and Northeast BC. That pipeline, we've been diligent in depreciating that pipeline well, and we just don't see that as being a problem going forward with tolls either. Thank you. Can I ask one follow-up on ANR? You guys have talked about getting back to that few hundred million of EBITDA, and it sounds like you're targeting that maybe for next year. I think you also mentioned something about maybe needing a rate case to get there. I'm just wondering if you're concerned that you're not going to get there without a rate case, or why the mention of the rate case? I am concerned that we're going to need extra revenue support on the system. As we put this new capital in, without changing the existing status quo, we are going to start compressing our ROE on it. As we put this capital in, and if we cannot find new revenue sources on it, we're going to end up discussing with our shippers one way or the other. Simply because we're going to put in, I said, half a billion CAD of capital, plus we've got ongoing maintenance capital that we're putting in. As we go through, if I don't do something about that, I will compress the ROE, and I will have to somehow enter in discussions or ultimately a rate case. I'm not going to say that we're completely confident we'll be able to do it without a rate case. As a matter of fact, I think we're going to have to have some settlement discussions with our shippers ultimately on it. It's just a function of the way the rates are set in the U.S. is that until you initiate that conversation, you're not going to recover those CAD. I'm looking a little bit in the future, saying that we're making investments right now, and we're going to look to recover them. Thanks very much. Those are my questions. Okay. Thanks, Matthew. Maybe just one more quick question from Robert, then we're going to take a break. Robert Kwan, RBC. Karl, when you look at the post-2020 timeframe on the mainline, if you drive the prairie north of Great Lakes right base down to CAD 1 billion, as you mark up the tolls, what does that do, say, Empress to Eastern Triangle? I don't know if you've looked at it that way or whether it's Empress TLGT into Dawn. This question is so dependent upon what the volume you're forecasting going through the pipeline is. I really hesitate to give you a definitive number because it changes depending upon what volume I ultimately get into it. I can tell you this. I think we'll still be able to maintain a toll into Dawn, either through going through Great Lakes or the mainline. As you can imagine, as we split off the Western system, because it's not going to be as full, I'm going to have a lot more pricing flexibility than I do today. The board has already given us pricing flexibility to move into it. I'm going to ask for more for the Western system when we split it off. I'm not going to be constrained by the traditional cost-of-service on that system. I ultimately believe we can still get gas into Dawn for under CAD 1.50, which is where it's coming in today. We might even be able to do better depending on how much gas I can attract in there. Certainly, you can go to Emerson and through Great Lakes and get it in there for under CAD 1.50 anyways in the future. I think we'll be competitive going into Dawn with the WCSB gas, even regardless of what's coming up through the Utica and Marcellus in that market. I know you don't want to talk specifically about volume, do you hold your FT at current levels? It sounds like you're just talking about maintaining tolls at roughly the similar- Yeah. -level versus a significant reduction. Well, yeah. Don't forget, I'm switching lots of capital. The way the settlement worked is there's a big bridging account in the Eastern Triangle that really takes some of this capital, the uncollected revenue from our high tolls today, from a high-cost service today, and amortize it on the Eastern Triangle. If I have the same volumes today going into Dawn as in 2020 when we have our Western system with only a billion, we're going to cut that substantially, cut that CAD 1.50 delivery cost substantially. I don't really plan on that. We have about just a little under a billion cubic feet a day. I'd say about 800 million a day. Various indigenous loads that I know that'll stay on the system, it's over a billion cubic feet a day is where we got to hustle to get the volumes on our system. If I have three and a half BCF a day still going to Dawn, my suspicion is you see that toll significantly decrease at a billion-dollar rate base to probably under CAD 1. I just don't think that's going to happen. If we do that would be great news story. We can get it on. I think we're setting up this Western system so that we can earn our return based on the indigenous volumes plus a little bit of extra. If we get a billion, a billion and a half cubic feet a day, we will be in really good shape on this pipeline. If we're still moving three, our tolls will be starting to come way down. Thank you. Okay, great. With that, I think we'll take a break. Obviously, due to those early technical difficulties, we're running a little behind time. Why don't we take a 15-minute break? We have worked in some time at the back end, still hope to have you done by roughly noon. Maybe if I could ask people to be back in the 10:20 to 10:25 timeframe, and we'll resume then. Hey, folks, if I could just get people to make their way back to their seats, we'll start within the next minute or so. Okay. Hopefully, folks had a chance to get a fresh cup of coffee and a little mid-morning snack. With that, we'll resume this morning's dialogue, and Paul Miller, President of our Liquids Pipeline business, is up next. Paul will give you an overview of that business and then be happy to take your questions. Is this one here? Yes. Thank you, David, and good morning, everyone. It's good to be back here today to talk about our liquids pipeline business. Our strategy remains relatively simple: efficiently connect supply to marketplace. Despite the significant decline we've seen in the crude oil price here over the last 15 months, crude oil supply continues to grow, and the demand for crude oil is expected to grow for the foreseeable future. Many markets in North America still rely on foreign crude oil, and those areas are shown in the red here on the pie charts on the graph, and those are the markets that we're pursuing as we grow out our business. As part of connecting this supply to the marketplace, Keystone is well-positioned and continues to penetrate the Mid-Continent market, as well as making significant inroads into the U.S. Gulf Coast. Energy East well-positioned to access Eastern Canadian refineries, as well as provide tidewater access to the U.S. Northeast market, the U.S. Gulf Coast, as well as to the growing international markets. The Keystone XL model remains the most attractive option to access the U.S. Gulf Coast. As we develop these large-scale projects, which will provide significant upside, we will stay focused on capturing regional plays in the intra-Alberta marketplace, as well as the United States, by leveraging our existing infrastructure and expanding our presence along the value chain. At the heart of our liquids business is our Keystone system, which has established itself as a premier crude oil transportation system by providing competitive tolls, shorter transit times, and exceptional product quality. It's a critical system that moves approximately 20% of Western Canadian production down to key refining markets in the United States, the U.S. Midwest, as well as the Gulf Coast. Since 2010, we have moved over 1 billion barrels of crude oil. We're constantly looking to improve the efficiency of our crude oil system. Over the last year, we were able to increase the average throughput on Keystone by over 30,000 barrels per day. As a result, we went to an open season, and we were able to secure an additional 15,000 barrels per day of 20-year contracts. That brings our total contract position on Keystone up to 545,000 barrels per day and has extended our average remaining length of those contracts to approximately 15 years, which will provide us visibility of Keystone's financial contribution for years to come. It is worth highlighting that Keystone is not impacted by the commodity price. The contracts underpinning Keystone are take-or-pay contracts, which means it will predictably generate approximately $1 billion annually going forward. We continue to progress our efforts to extend the Keystone system reach into the U.S. Gulf Coast refining center that refines more than 8 million barrels per day of crude oil through our Houston Lateral and tank terminal projects, as well as partnerships with and toiling arrangements with Magellan, Phillips 66, and the Bayou Bridge partnership. We'll extend Keystone's reach west to the entire Houston and Texas City refining complex and east into the St. Charles market, which will provide us direct access to over 4.5 million barrels per day of refining capacity. Extending the reach of the Keystone system is expected to enhance both our short- and long-haul volumes. We will leverage this growing platform through additional pipeline laterals, business combinations, interconnections, as well as implementing terminal solutions that will extend our market reach further and enhance our ability to pursue regional plays in the U.S. Gulf Coast. Beyond expansion into the U.S. Gulf Coast, we are also advancing our intra-Alberta liquids pipeline projects as part of the company's CAD 13 billion of visible near growth opportunities. Looking first at Northern Courier, this CAD 1 billion project will transport bitumen and diluents between the Fort Hills mine site and Suncor's East Tank Farm facilities north of Fort McMurray. The project is underpinned fully by a 25-year contract with the Fort Hills partnership, and this is a consortium that includes Suncor Energy, Total Canada, and Teck Resources. Construction is underway. It is about 30% complete and is expected to be in service in 2017 in advance of the Fort Hills mine. Our intra-Alberta liquids mainline, Grand Rapids, continues to advance despite challenging market conditions. This is a CAD 3 billion pipeline project. It is a 50/50 joint venture between us and Brion Energy, which is a subsidiary of PetroChina, and Brion has also signed a long-term contract to ship on the pipeline system to underpin the investment. Construction is progressing on phase 1, which includes the 20-inch line from Northern Alberta down to Edmonton, and then the 36-inch line in between Edmonton and Heartland. The first phase is expected to come into service in late 2016 for initial crude deliveries north to south and for our anchor shipper, and we hope to announce additional shipper commitments here shortly. Our recently announced joint venture with Keyera involves the 20-inch piece in between Edmonton and Heartland, and this joint venture is incorporated into our phase 1 of Grand Rapids and will provide additional and enhanced diluent supply to our Grand Rapids shippers. Timing of the larger 36-inch line will be a function of market demand, and absent clear indication of strong market need, we will exercise capital discipline and slow development to align the in-service date with appropriate market demand. Contract profile of the 20-inch line generates stable earnings and cash flow and positions Grand Rapids to competitively expand and capture additional volumes as the marketplace recovers. EBITDA profile from our liquids business remains attractive. Our Keystone system continues to produce solid results with the predictability of its largely contracted volume. We do not anticipate a material change in performance of Keystone, although spot volumes will be a function of differentials in the marketplace. Three new projects will come into service by 2017 and as they ramp up through 2018 beyond, will generate stable earnings and cash flow from a considerably contracted base with approximately CAD 150 million-CAD 200 million of incremental EBITDA annually. Combined, our liquids business is expected to generate approximately CAD 1.5 billion or approximately 20% of TransCanada's consolidated EBITDA in 2018. Like many others, we were very disappointed by President Obama's decision to deny the Keystone XL permit, which goes against the strong market need and demand for this project and the high public support. Keystone XL remains critical energy infrastructure and the most attractive, safest, and least carbon-intensive way for Canadian crude oil to access the U.S. Gulf Coast. With these strong market fundamentals and shipper support, Keystone XL would generate an additional U.S. $1 billion annually at EBITDA if built. We'll continue to review all options and avenues available to us, and we'll announce next steps as they become crystallized. Turning to Energy East, we recently announced our intention to amend our NEB application to remove the Cacouna, Quebec terminal and proceed with a single marine terminal in Saint John, while continuing to serve the three refineries along the route in Montreal, Quebec City, and Saint John. Market access remains critical for producers, as does the certainty of supply for the refiners. In addition to accessing these refineries in Canada, the Saint John Terminal will provide tidewater access to serve the U.S. markets in the Northeast and the Gulf Coast and international markets in Asia and Europe. Sole Canadian market access and supply solution allows the country to end its dependency on foreign oil, generate significant economic stimulus across multiple provinces. It will allow the Western Canadian producer to access Tidewater. It's a 1.1 million barrel per day pipeline. It's strongly underpinned with about 1 million barrels per day of contracts. When in service in 2020, it's expected to generate approximately CAD 1.8 billion of EBITDA annually. Keystone XL and Energy East are long-dated projects which provide tremendous upside. Beyond these larger projects, however, we remain focused on growing our presence and business activity in the North American marketplace. There's more to our story than Energy East and Keystone XL. With declining production growth, we have seen a slowing in demand for infrastructure in the Alberta marketplace and in the emerging basins. With a disciplined approach, however, we are positioning our business development activities to capture opportunities in these markets when the environment recovers. We will pursue opportunities around our asset base and those which may extend beyond our geographical footprint as we explore new low-risk developments and acquisitions. We will expand our business along the liquids value chain. This includes potential expansion into transporting other commodities and terminal and transportation services. We're in the final stages of developing a marketing business to optimize our asset base and assist with market development. Notwithstanding the delays in the bigger projects and softer commodity markets, we will remain very active and very focused. We've developed an enviable position with our Keystone system that generates stable and predictable results, a trend that will continue for the foreseeable future. We will bring over CAD 2 billion in commercially secured projects into service over the next couple of years. We will deliver EBITDA growth over the next several years. Our approach to the liquids business is focused. We'll continue to improve our base business. We'll develop existing smaller-scale projects. We'll exercise discipline to secure growth while maintaining options for the market recovery. We will persevere to capture the significant upside of our larger projects. That concludes my comments, and I'm happy to take any questions you may have. Once again, just raise your hand and we will get a mic to you. Stephen Padgett, FirstEnergy. I'm glad the mic works. Paul, with Enbridge opening a pipeline to Patoka by the end of the year, could this mean pipeline flows on Keystone all the way to the Gulf might increase? Hard to say, Stephen. We have significant contractual underpinning on Keystone, possibly 90%. Those contracts are serving specific markets. I would anticipate our flows to continue to be primarily to Patoka and Cushing. If you look at our contract split, it's about probably two-thirds Patoka, one-third Cushing. We do provide the opportunity for shippers to divert volumes for an added toll. If they didn't want to ship to the Patoka marketplace, they could ship down to the Cushing marketplace and then further down to the Gulf Coast. I think it will be a function of market differentials for both those contract shippers, where they want to divert those barrels, as well as where the spot barrels might end up. I do anticipate a core volume, however, continuing to move to Patoka, a core volume continuing to move to Cushing. With our advancement of our projects in the Gulf Coast, as well as our arrangements with the various incumbents in the Gulf Coast, I would anticipate our volumes to the Gulf Coast increasing as well. Well, thank you. A follow-up, if I might. You said you're in the final stages of developing a marketing business. I know some marketing businesses, their missions are to increase throughput and bring more volumes onto the system, but your pipelines are near full, so your marketing division's mission would be to use available spot capacity or what would it be? Yeah, that's correct. On our long-haul volumes, we are effectively 90% full with 20-year contracts. On our Gulf Coast extension, where we take barrels at Cushing, we have a shorter contract profile there, and it's a shaped profile where contracts fall off over one, two, three, five-year type periods. We've been successful in recontracting that position, but there still remains available capacity on the Cushing to Gulf Coast piece, and there still remains capacity on the Hardisty piece as well. The role of this entity will be to optimize our capacity on the existing system. Thank you. You're welcome. Thanks, Steven. Paul? Paul Lechem from CIBC. Just wanted to ask your views on what the utilization of Energy East will be when it opens in 2020. I know you have it contracted, but how should we think about the volumes that would've flowed on Keystone XL? With some of the contracts on Keystone XL, are they sort of duplicated because producers weren't certain which one would go ahead? Or how should we actually think about the actual utilization of Energy East Sure when it opens? First of all, I think utilization of any ex Alberta pipeline that's in development today or proposed, it will be a function of the supply growth. That supply growth will be a function of the pricing environment, both prevailing here over the next couple of years as well as the long-term pricing expectations of the producer. Based on consensus, if you wish, there is an expectation that we'll see upwards of two million barrels per day of growth between now and into early next decade. Based on that supply forecast, there will be a requirement for Energy East and given the premium market access that Energy East will provide, it should run substantially full to provide that tidewater access. The other aspect of Energy East that Oh, I should back up a bit then. Given the contracted nature of Energy East, these are long-term take-or-pay contracts, if the producer does not nominate their barrels, they are still responsible for the fixed toll component of the toll. From a transportation economics assessment perspective, the producer will look at it on a variable cost basis. If the economics of moving on Energy East and paying the variable toll are more attractive than other ex-Alberta pipeline opportunities, they will move those barrels on Energy East. The other aspect of Energy East is the Upland Pipeline, which moves barrels from the Williston Basin in North Dakota. Today, most of the pipelines out of the Williston Basin and primarily the Bakken formation, find their way down to the Cushing market and further south into the Gulf Coast market, where the competitiveness of the Bakken barrel is challenged because of all the light crude production we see in the Permian and Eagle Ford basins. We will be able to pull barrels from the Williston Basin up into Energy East for transportation into the Eastern Canadian market and into the Eastern United States market. That Eastern United States market today is being fulfilled primarily by rail, the Bakken barrels moving to the Northeast. We would anticipate offloading a lot of the rail transportation of those light barrels coming out of the Williston Basin into the U.S. Northeast, again, as well as moving significant ex-Alberta barrels as a result of our long-term tolling arrangement with the shipper. Okay. One follow-up, if I may. As you get ready to file the amended application to the NEB, can you give us some sense of the magnitude of cost increases since the original filing, and what are the elements that have contributed to cost revisions? Sure. I won't be able to give you any visibility into the extent of the cost increase. We will be able to provide some visibility once we get to the application, which we would anticipate filing here over the next couple of months. We're targeting year-end to make that filing. As far as the cause of the cost increase, it really revolves around project definition and refinement of that project definition. We've done some additional engineering work. We've done some additional routing assessments. We've had some reroutes associated with some of our consultation process, listening to the constituents and the issues they may have with some of our original routing plans. Between just further scope and schedule definition, some reroutes, we're going to see a cost increase. Andrew? Andrew Kuske, Credit Suisse. Paul, could you just give us some perspective and context on how you think about the PP process on a go-forward basis? Because obviously, Upland Pipeline crosses the border. You need a presidential permit on Upland Pipeline. Is there some workaround for Keystone XL? Could you look at rail connectivity, effectively building most of the line but not crossing the border with a pipe? How do you think about it for Alberta Clipper, just more broadly, the PP process, and then just specifically what you can do in some of your situations? You say PP process? No, the PP, the presidential permit process. Oh, presidential permit. I'm sorry. To start with, yes, the Upland Pipeline will require a presidential permit. Upland is scoped to provide transportation within the U.S., within the Williston Basin, as well as export capacity up into Energy. It has its independent utility with the intra-U.S. market, if you would, but it does provide significant opportunities for the Williston Basin producer to access those very critical Northeast U.S. markets, as well as the Eastern Canadian marketplace is very attractive for that Bakken producer. It does require a presidential permit, and we have filed with the State Department that application. Far as the other opportunities, we're going to continue to look at intra-U.S. plays. We have seen a slowing in the demand for that infrastructure. It's a marketplace that we're very interested in right down the mid-continent. Our business model has us seeking long-term contracts to underpin those investments. There was a reluctance, if you wish, on some of the emerging basin producers to enter into those long-term contracts. The most we could see was probably in that five to seven-year period. The willingness has shrunk even further until they play out their reservoirs a bit here and get better visibility into the pricing environment. Notwithstanding, we continue to pursue opportunities to build out the intra-U.S. infrastructure, and that's where we're focusing our PD activities. In that mid-continent down the U.S. Gulf Coast, where we have that geographical footprint already. As far as rail is concerned, there's been a lot of talk about, let's build a rail facility and just build from across the border down and connect to where we were going to otherwise. There's still other permits we need to build out that pipe. For example, we're going through a Nebraska process right now. When you look at rail economics, the real cost of rail is putting it on the car and taking it off the car. Once you're on the car, there's not a lot of advantage to moving it down to, say, a point in Montana, putting it on a pipeline, and shipping it down through the pipeline system. Once you're on rail, you might as well extend it right to a central point where you can connect with pipes and other interconnections to access the marketplace. Rail as well has slowed down considerably as a mode of transportation. We've seen a considerable build-out in rail here over the last three, four years. Much of it's underutilized today with pipe picking up more volumes with the slowing growth. It's something that is always sort of in the portfolio, but the need for rail right now is fairly muted. Sorry. Just give it a sec, please. Hey, Paul, it's Dean Highmore from Investors Group. Just had a question on your Keystone Pipeline system. On your slide, you mentioned you had a 15-year duration contract on Keystone. I was just wondering what the process was for recontracting in 15 years' time. Do you look to maybe do a blend and extend with some of your shippers before that duration runs out? With Keystone, we are a common carrier, which dictates that when we look to recontract or offer up new capacity on the system, we offer that capacity to the entire marketplace, and we fulfill that obligation by going through an open season. We have in place today, again, fully contracted pipe or effectively fully contracted pipe, other than the portion that we have to set aside for spot or walk-up shippers. I would anticipate that as we get close to that 15 years, first of all, we don't know what the regulatory environment's going to look like at that point. If we're still in the same regulatory environment, we would enter discussions as to what the marketplace wants as far as volume, tolling arrangement, tolling design, et cetera, and then structure our open season accordingly. Any other questions for Paul? We'll take one more from the back there. Al Nagaraj from MA. You got this slide that talks about CAD 2.4 billion invested today on Keystone XL. Do you expect some kind of write-down on these investments? How do you look at these investments at this point in time? No, I think we're continuing to review our options on Keystone XL. We have CAD 2.4 billion invested, I think, prior to the interest during construction. A lot of that CAD 2.4, probably about half is in tangible assets. From a recovery perspective, we're probably able to recover 40% of that, if you wish. We haven't finished exploring our options following the President's denial of Keystone XL. Again, as we crystallize our next steps, we'll get back to you. Thank you. Thanks, Paul. With that, we'll turn the podium over to Bill Taylor. Bill is President of our Energy business. Bill will provide you with an update on that business, again, we'd be more than happy to take your questions. Thank you, David, and good morning, everyone. It's great to be back with you today. Of course, it's always easier to be up in front of you when I've got a good news story to tell, I think that's very much the case for the Energy performance in 2015 and looking forward. I say that for three reasons. One, because we've got, importantly, a few things to the finish line in 2015, delivering on some growth. Secondly, as Russ and Alex alluded to in their earlier remarks, our Energy platform has shown a tremendous amount of resiliency through a tough period. Thirdly, we've got a lot of excitement for our growth prospects in the future. I want to today go over these three points with you in a bit more detail. Finally, like my colleagues have done, give you a bit of an outlook into 2018. To expand on the points that Russ made earlier around stability and predictability, let me discuss that as it relates to our energy segment. Today, we operate a business that is a diverse portfolio of assets across a similarly diverse set of markets and geography. With 19 plants and just under 11,000 megawatts of capacity, we are the largest private sector energy company in Canada. This number will grow to 21 plants and approximately 12,500 megawatts with the startup of our Napanee project in Ontario and with the successful close on the Ironwood facility in Pennsylvania. In addition to geography, diversity of technology and fuel type also provides us with stability. Roughly half of our power business is natural gas-fired, with another third coming from power that we produce from emissionless sources, which includes nuclear, hydro, solar, and wind. The remainder, only 15%, is coal-based. Turning to our revenue diversity. At present, just over half of our overall business is underpinned by long-term contracts with an average term of 14 years, providing a very stable base. Additionally, all of our U.S. power operations operate in organized and mature FERC-regulated markets that have well-developed capacity market mechanisms behind them. Capacity payments provide reliability standby payments to generators who are available to produce electrical energy when their system demand calls for it. Over half of our U.S.-based revenue in the energy segments comes from these predictable capacity market mechanisms. With more and more renewable supplies entering the markets in the U.S., these mechanisms are increasingly becoming considered necessary and important tools to ensure reliability. These stable revenues, taken together with our energy hedging programs, our wholesale marketing activities, allow us to manage and optimize our portfolio through price variability periods. This resiliency that I mentioned is evident in our results. The energy segments asset portfolio has delivered a stable range of EBITDA over many years. This diversity has allowed us to shield our overall financial results from large swings caused by any regional headwinds that can occur from time to time in the markets in which we operate. A good example of this would be 2014. Power prices were starting to soften in Western Canada, our results in N.Y. improved, this, combined with the startup of our solar operations in Ontario, led to solid overall results on the year. In the current year, 2015 to date, our Western power operations have continued to come under some pressure as low prices in the Alberta market have persisted. Indeed, spot prices in Alberta have declined almost 60% year-over-year in our western region. Similarly, we have been challenged with our natural gas storage business as spreads have come under pressure with some issues with regards to receipt volumes on the NGTL system. Even given these two relatively strong headwinds that have affected us in the West, we've been able to offset these with the positive performance and strength in the rest of our portfolio, such that our overall 2015 EBITDA year-to-date has remained slightly ahead of where we were last year. Before I get into a bit more of an in-depth discussion of certain of our assets, let me touch on our overall energy strategy. First, we continually strive to maximize the value of our existing assets. My team is quite focused on the pursuit of excellence in our plant operations and relative to the commercial management of our positions. We have a strong track record of success in that regard. We will continue to leverage our existing footprint to grow our business. Additional refurbishments at Bruce Power are an obvious example of this. I will discuss this in a bit more detail in a moment. Another example would be our operations at Bécancour. In 2015, we finalized negotiations with Hydro-Québec to enhance our offerings from Bécancour to include a peaking service from this originally designed baseload facility. This new service will begin operations in 2016. Our acquisition of the Ironwood facility in PJM in the U.S. Northeast is another. It adds a physical resource to our well-established marketing position in this region. This acquisition demonstrates our ongoing strategy to opportunistically grow our business through acquisitions and strengthen our market position in regions that we know and understand well. Beyond these organic opportunities, we continue to consider growth of our business in other new areas. We will continue to do that. It is important not to forget that the overall power generation fleet in North America is aging out. I was just looking at some material in respect of the New England market in NEPOOL. Over a third of the base of existing capacity in New England is over 55 years old. Senior citizens, if you will, that will soon need to retire. This reality, combined with a public policy framework that is favoring cleaner, lower or non-carbon-emitting resources, is creating opportunity for us. I believe over the next number of years, this will create a significant need for new gas-fired generation and for more renewables or other non-emitting sources of power. These opportunities are real. TransCanada is well-situated to capture them. Let me turn now to our recently announced acquisition of the Ironwood plant located in the Pennsylvania, New Jersey, Maryland, or PJM market area. The PJM market is the largest and most liquid energy and power region in North America and one in which we're very comfortable given our already substantial business in that region. The Ironwood facility is strategically located and well-connected to Marcellus shale gas and is very well-positioned in that regard. The PJM market is, like many other locations in North America, in the midst of a transition away from coal-fired power generation. The Ironwood and other plants like it in PJM are filling the gap left behind by less production and retiring coal capacity. The plant is expected to run as an intermediate to baseload facility going forward and to produce between 90 and $110 million of EBITDA on an annual basis. Shifting now to an important greenfield growth project for us. I'm happy to report that we did commence construction of the Napanee Generating Station during 2015, at the beginning of this year. Napanee is a CAD 1 billion combined cycle natural gas plant that will be capable of generating approximately 900 MW of electricity. All of the output is sold under a long-term 20-year PPA with the Ontario Electricity System Operator in Ontario. I can report the construction is progressing very well, and we anticipate commercial operation in late 2017. Moving now to Bruce Power. As you know, Bruce Power is an extremely large and important facility, capable of generating over 6,000 MW of power, or roughly 30% of the needs of Ontario's power system. In 2015, the facility achieved a number of excellent operating and technical outcomes. The initial issues on the Bruce A site following the restart of Unit 1 and 2 are now firmly behind us, and the availability and force loss rate on the A site are now much improved and in line with Bruce B. Next, Bruce was recognized internationally by an independent review agency regarding a top rating for Bruce B power operations. Finally, in 2015, a number of very complicated outages at Bruce were completed ahead of schedule and below budget. This included the significant and complex vacuum building outage, or VBO, at Bruce B. This has all added up to Bruce having an excellent financial year in 2015, and despite the burden of the downtime of all the outages that I just mentioned, if things go well in the last quarter, I expect that Bruce Power will deliver close to CAD 300 million of EBITDA for TransCanada this year. Looking to the future, Bruce is of course, actively pursuing the potential opportunity to refurbish Units 3 through 8 at the site. As part of the Ontario government's long-term energy plan, the province has continued and strengthened their commitment to increasing emission-free electricity generation. Bruce is well-positioned to continue to provide the province with this much-needed power while doing so on a cost-effective basis for the consumers in the province. Bruce is currently in negotiations with representatives of the Ontario government respecting the Units 3 through 8 refurbishment. I can report that discussions are progressing well and in a positive direction. This is a very large transaction and will mean multi-billion CAD of investment over multi-years for Bruce Power and for its owners. It is a big opportunity, it is complex, is thus taking some time to conclude. Rest assured, Bruce Power has learned a lot from the restart of Units 1 and 2. The lessons learned from that activity are being incorporated into the plans and into the commercial arrangements that are being worked. The bottom line outcome for Bruce will see a significant extension of its life. Not only would this serve the Ontario consumers well for many decades to come, it will become an important growth platform for TransCanada and for our energy segment. Refurbishment of Bruce Power just makes economic and technical sense for all stakeholders. We thus are very focused on seeing Bruce Power bring this opportunity to fruition. Now turning to the Alberta power market. We continue to see a market in Alberta that is well-supplied, in fact, a bit oversupplied, at least in the near term. The recent capacity additions, together with soft demand growth from the downturn in the Alberta economy, combined with low natural gas prices, have resulted in low power prices that we're experiencing today. As you can see in the graph, the average Alberta power pool price for the third quarter of 2015 was approximately CAD 26 a megawatt hour. Low prices are expected to persist into the near future. These prices, of course, are well below any estimate of replacement cost in this market. Alberta is facing some tough choices as it relates to its power supply plans going forward. This combination of an all-time weak price environment and pending, or some would say, likely government policy action, either increasing incentives to promote renewable power in the province or regulations affecting coal policy, or both, we think leave the Alberta energy-only market at an important crossroads. Within this context, the new Alberta NDP government's election platform contains some significant climate action items that are poised to have a big impact on the power sector in Alberta. Indeed, one of the first actions taken by the new government was to extend and strengthen the expiring regulations under the Specified Gas Emitters Regulation that governs carbon emissions. These revised regulations on a phased-in basis essentially triples the cost to emit carbon in Alberta. A climate change advisory panel to review Alberta's climate change policy and provide advice to the new cabinet on a permanent set of measures was implemented, initiated, and completed. It seems clear that this new government in Alberta is focused on actions that will reduce carbon emissions in the province, including the potential for accelerated action on the wind-down of coal-fired power production in Alberta. The specifics of where this may be heading may become clear in the near term, as it is expected that the government may be announcing some of these initiatives in advance of the COP 21 climate conference that's upcoming in Paris. Regardless of how the Alberta power market may unfold, however, TransCanada is well-positioned to participate in the new path that Alberta may be taking coming out of this current crossroads. It's important to recognize that our current business was very much grounded on the last time there was a significant inflection point in Alberta. TransCanada was well-positioned at that time and built a business over many years. I expect that that same opportunity and that same possibility of an inflection point is facing us today. From a growth perspective, as I think I mentioned to you last year, we do look at a lot of interesting opportunities on the power side. We continue to cultivate a suite of future development opportunities from this effort. First and foremost, this is our Bruce Power refurbishment opportunity that I've already reviewed. Beyond that, we also see big opportunity for growth in natural gas-fired generation, further growth in renewables, and growth in projects that are aimed at backing up or firming up renewables that are entering the market. As highlighted when discussing our strategy, we are also participating in the development and the repowering of the power sector in Mexico. Mexico is a region that we know well, given the success that Karl went over when he was discussing our gas pipeline business in that region. Organic growth examples include considering the repowering of sites like our Ocean State Power facility and our critical New York City infrastructure that we own in the Ravenswood facility. You can expect that when the market is signaling need for new capacity in these regions, we intend to respond with projects that will meet that need using these existing, very well-situated platforms that we have in our portfolio to leverage into some new opportunity and some growth. We also see opportunities in the power M&A space, and we will be active, opportunistic, and disciplined when it comes to considering these, just as we were with the recent Ironwood acquisition. Much like the other presentations that you've heard this morning, I'd now like to update you on our outlook for the energy business looking out through 2018. With about 12,600 MW of capacity coming from 21 plants, EBITDA is expected to grow from about CAD 1.3 billion expected in 2015 to approximately CAD 1.6 billion in 2018 with the addition of Ironwood and Kiamani. Importantly, this outlook does not include any possible consideration of improvement at Bruce Power should there be agreement reached relative to the refurbishments that I went over earlier. If that comes to pass, we would intend to update the market specifically in relation to that opportunity. In closing, let me leave you with some key takeaways. First, consistent with our overall corporate message of resiliency and predictability in our business, we have and continue to build a stable energy business with assets that are either underpinned by long-term contracts or by other stable revenue streams and are extremely competitive in the markets in which they operate. The diversity of our business is one of our key strengths, and it allows us to withstand regional headwinds that can occur in the competitive markets from time to time. The growth of our business in the U.S. Northeast and Ontario that I've gone over this morning deepens our positions in these key markets and will continue to foster a solid market position. Bruce Power is actively pursuing a large refurbishment program, and we look forward to being able to update you on this as it progresses. We have the critical mass in the most attractive markets in North America, and this base, along with our strong expertise, position us very well to capture opportunities going forward. Finally, just as we've done with the Ironwood acquisition, we continue to look for opportunities to step out into new markets, but always doing so consistent with our strategy of building a stable and reliable business. Thank you. That's it for my prepared remarks, and I'd be happy to take some questions. Okay. Matthew. Sorry, just come right back to you, Ben, in a moment. Morning. Thanks. Matthew Akman, Scotiabank. My question, I don't know if this is for Russ or Bill, but it relates to the acquisition of Ironwood and generally power acquisitions and merchants or mixed merchant, call it, kinds of assets like Ironwood, where TransCanada obviously has significant expertise in this area, and not just in operations, but also in marketing. Prices on assets seem very reasonable relative to, say, certain contracted renewables, and as you've said, it's accretive. On the other hand, investors don't seem like they're very optimistic about these assets, or at least they're not in favor with investors, and I'm not sure how rating agencies view them. I'm just wondering how you see that difference and whether it's something that constrains your appetite for these kinds of assets, or because you think it's the right thing to do in the long term for TransCanada, that you're prepared to just keep going forward with those types of acquisitions. Well, I would just start, and then maybe Russ wants to add to my remarks. I would say that we looked at an awful lot of assets before landing on an asset like the Ironwood facility. I think you can consider it that it's viewed as extremely complementary to our existing platform. While it can be viewed as having a negative complement to our business because of the fact that it doesn't look like an Ontario plant that might have a 20-year contract. I think that, as I've mentioned in my remarks, we have a lot of good understanding and a strong sense of stability that comes from the capacity signals in PJM. The retiring capacity that we see going forward will add strength to that market, as well as the relative energy competitiveness of that asset, given its situation and its close proximity to gas supplies. In addition, we are well-situated. We're serving over 1,000 megawatts of load in the PJM area. We've been doing that for, and building that up. It varies and ebbs and flows in volumes from year to year, but we've had great success with that margin business, and we see this asset as being very complementary to our existing operations in the area, beyond the physical operating points that you raised. I think you can see us continue to look for these opportunities, but they're going to be niche opportunities that fit really well with our existing platform, as opposed to a wholesale addition of significant merchant facilities across the continent. Yeah. I'd just add, as I think about it, Bill, as he described in describing his business, thinks about it as a portfolio. The bulk of the portfolio is contracted and then low cost and with capacity payments that we look for building a stable business. Then I look at it as an overall portfolio in the whole company. The whole company is looking for similar kinds of things. Through that process, we develop considerable expertise in these markets and an opportunity to acquire an asset like Ravenswood, where we can acquire it at six or seven times EBITDA, augment our portfolio, and add accretion and value to our shareholders. We'll continue to do that on a large-scale basis. We're not looking to add merchant power in a large component. As a portion of our portfolio, I look at our plans going forward, where the commodity exposure, return on capital employed, and our cost of capital. As long as we keep it in a percentage that's small enough in our portfolio that it doesn't affect our capital employed, it actually increases our spread between return on capital employed and our weighted average cost of capital, which just drops to the bottom line for our shareholders. That's the way we think about it in a portfolio sense. We're not going to pursue it on a large scale, but in all of our businesses, we will grab some merchant positions. You can see that we've done that in our oil business. We'll look to probably do more to enhance the merchant aspects of our pipeline business by adding marketing and trading capability. We've done it in the gas side of our business, in the storage side of our business. I think return on capital employed and our cost of capital, and as long as we keep it in a percentage that's small enough in our portfolio that it doesn't affect our capital employed, it actually increases our spread between return on capital employed and our weighted average cost of capital, which just drops to the bottom line for our shareholders. That's the way we think about it in a portfolio sense. We're not going to pursue it on a large scale, but in all of our businesses, we will grab some merchant positions. You can see that we've done that in our oil business. We'll look to probably do more to enhance the merchant aspects of our pipeline business by adding marketing and trading capability. We've done it in the gas side of our business, in the storage side of our business. I think it's a natural sort of component of our overall portfolio. As I look forward, we're about 90% sort of secured revenues today that are underpinned by regulated models or contracts. As I look out to 2018, that percentage grows so that the actual percentage of merchant exposure actually declines. Diversity gets greater, our size gets greater, we do believe that adds value for our shareholders. Thank you very much. Thanks. Thanks, Matthew. Ben? I had a question on Bruce Power refurbishment. It's obviously an important priority for you now, just given the amount of time you spent here on the potential opportunity. As you talk to your suppliers and you get closer to the final stages of negotiation, are you able to quantify, or have you quantified the potential capital investment opportunity with Bruce Power refurb net of your ownership? Sorry, could I quantify the capital? Is that what you're saying? Yeah. I think the way you can consider the Bruce opportunity is there's a lot of detail being considered as to how the capital's being considered in different buckets. The current view is that the project, we're looking at it quite a bit differently than units one and two refurbishment because those units were in an idle and shut-down state when we first initiated that project. In this case, there's an awful lot more known about the state and scope of refurbishment, the capital's really being considered in a couple of buckets. The first bucket would be capital that needed to be spent to continue to extend and meet the longer-term refurbishment program schedule that's under discussion. The other capital is for the actual reactor work or the major component repair component of the work. A rough number for you to consider would be that each reactor for both components of capital that I just mentioned would be around CAD 2 billion per reactor. This would ebb and flow over the entire program because that life extension capital that would take you between MCR or reactor work would come in a variety of pieces over time. An approximate number that you could use would be CAD a couple billion dollars per reactor. Sorry, Bill, would it be fair to say that number would be invested over quite a prolonged period of time? Obviously, as I think as Bill's highlighted, you got some work up front that continues to kind of extend the operating life to the reactors before you get to that point. Yeah, absolutely. The program that's under discussion would involve one or perhaps a maximum of two reactors being offline at any point in time. Sorry. Andrew? Andrew Kuske, Credit Suisse. How do you think about your positioning in the Alberta power market, especially as you highlighted the transition away from coal to natural gas? basis versus the incumbents in that market? Well, I guess the first comment I'd make is that I think I'm pleased that I have about the least amount of capital tied up in that market, given the size that we are, particularly as it relates to the coal exposure. I do think, as I mentioned in my remarks, I think that the market is at an inflection point. The government schools have been very clear that they wish to see a turnover and a move away from coal-based emissions, and they wish to see more renewables come into that market, neither of which we think can happen when prices are CAD 26 a megawatt hour. I think that we can expect a change. TransCanada is not afraid of change. We've demonstrated through our activities in Ontario, to use an example, and through growth and development of other regional markets in the U.S. that our business model is grounded in understanding these markets well and taking action only when we think it's opportune and the right time to do it, but also under a variety of different market circumstances. We're involved directly in the discussions that Alberta Government are undertaking right now to consider changes that they may consider to the structure and the incentives that are existing in Alberta. I'm confident that we're pretty well-positioned, not only given our free capital that we could deploy, but also just our history and our understanding of that market to invest when the time is right. Just as a follow-up, do you think you have an advantage position with the transition of the power market away from coal to natural gas, in part because of the gas pipeline footprint? Yeah, I think so. We've had some discussions and we made a formal and public submission to the government that involved a view we have about how Alberta could transition away with and reduce emissions significantly by undertaking some more accelerated conversion to gas. That, we think is sensible. Karl talked about the tremendous gas volumes that we see coming onto the NGTL system and the tripling of the resource base. These are very significant numbers and I think indicate that gas prices are going to be low and long, if you will, for some time. I think this is a good environment for Alberta to consider that the impact on consumers of moving to a more gas-based power generation fleet in Alberta would not be as costly as it might otherwise have been years ago. That's right. Mr. Al Nagarajan, Distillience. I read an article that talked about the price of natural gas going higher and the number of coal plants that needs to be almost shut down, and there's not going to be a significant drop in coal demand and increase for natural gas plants. I just want to know what your views on that thought were. Natural gas prices are slowly increasing, and eventually it's not going to be really economical to further close coal plants. I guess I would say bluntly, I disagree with that view. I think, as I just mentioned, that gas prices North American-wide are not poised based on any realistic outlook that I've seen to increase. I think you've got growing and expanding production in various regions of the U.S. and similarly in British Columbia and in Alberta. I think that at least for the next decade or so, that the issue that you're raising would not come to pass. I don't see a strengthening gas prices in that period. Even with the LNG exports in the next four or five years? Well, I think that the LNG projects, they certainly will impact, and I think they're a necessary relief valve, if you will, that producers will be looking for to access markets. I think that the timing of those and the progression of them will be staged in a manner that it would not create price shocks. That's the perspective I have. Thanks. Okay. If there are no more questions for Bill, thanks, Bill. Appreciate that. We'll now head it to the home stretch with Don Marchand, our Chief Financial Officer, who will now give you an update on the financial front. Thanks, David. Good morning, everybody. I think I heard about a dozen references earlier from my colleagues that Don will cover that. We'll have to dive right into this here right now. Spend the next 20 minutes or so pulling together what you've heard today into the numbers and what it means for the finance plan and coverage ratios and the like here. Most of the numbers will be in Canadian dollars. We see a 1.30 currency through our planning period here, which is embedded in these numbers. From a tax perspective, the next couple of years anyway, we see an effective tax rate in the 27%-28% range, excluding flow-through taxes on the Canadian regulated systems. With that, just want to spend a few quick minutes here reviewing our fundamental tenets in financing. First and foremost, we're focused on building long-term annuity streams and investing in regulated franchises. As has been mentioned over the course of the morning here, where we have market risk, it's contained as a percentage of the portfolio, and where it does exist, it generally is baseload power assets, lowest point of the dispatch curve, and we have active hedging programs on top of that. Volume risk as a percentage of the portfolio is limited, and I'll touch on that in a minute here. We finance those assets with long-term capital. We have CAD 21 billion in book equity. The average term of our debt is 16 years, so long-duration assets matching long-duration liabilities. High visibility to the biggest input cost to our business. Lock in a margin between revenues and financing cost. Repeat over a bigger asset base. We don't compromise our long-term prospects due to short-term events. We preserve our ability to act at all points of the cycle. I would say paranoia is a celebrated trait in our finance group. Fundamental to that is the A credit rating. It allows us access to significant pools of capital at low cost for significant term and significant size, again, throughout the economic cycle. It differentiates us at stress points of the economic cycle, like we may be seeing right now. I believe it differentiates us as the counterparty of choice when you do have customers looking at 20, 30, 40 year assets in some cases. Who do you want to do business with? I think this is a differentiating factor. I'll speak a bit about our risks in a minute, I would note that we have seen a shift from regulatory to counterparty risk over the past couple of years as we have taken on many more contracted assets. This is a core competence to the company, we have a long-standing track record there. We are dedicated to disciplined cost and capital management. As was mentioned by Alex earlier, there's a broad cost initiative underway right now. On the capital side, balancing dividends, financial strength, and investment in new growth. This is all looked at through the lens of per-share economics, I would reiterate Russ' comment earlier that the share count has remained largely static since 2011 when we turned off our DRIP program. We are organized in a manner that doesn't resemble the back of your stereo. We see value in simplicity and understandability of corporate structure. We're not averse to financing vehicles. We have a pipe LP right now that's listed on the NYSE. We have had power LPs and processing LPs in the past. Again, the simplicity is something that we think is valued in the marketplace. Looking where we're at today, as you've heard over the course of the morning, again, the base business is in very solid shape, delivering excellent results. The fleet is performing very well. Points of weakness right now would be the Alberta Power market and storage spreads. Great Lakes, I would say, continues to be a work in progress, heading in the right direction. Mentioned the cost initiative that's underway. We are right in the middle of it right now. There will be elements that go to capital, elements that go to our customers, elements that drop to the bottom line, we'll be in a better position when we release year-end results to give you a little more color on the cost and benefits of that. The funding program this year has gone exceedingly well, we've actually put a fairly healthy dent in 2016 funding at this point. I'll walk through that in a minute. We are one of the few A credits left standing in the sector. We often use the phrase, it doesn't mean anything until it does, then it means a lot. We may be approaching one of those inflection points right now. We are seeing credit spreads diverge quite substantially based on credit right now, we are actually seeing access squeezed by some parties. I would note that the Keystone denial was not a ratings event. That was a positive comment from our rating agencies. In terms of near-term capital needs, again, I'll walk through this program in a couple of slides here, but about 60% of our capital needs through 2018 will be met through internal cash flow after dividends. We have many other levers to pull. Looking at our large-scale projects, we continue to progress them as, call it asymmetric options to the upside with limited development cost risk. We will not set aside capacity for those projects. They are eminently financable projects on their own. They are all long-term contracted energy infrastructure, and we believe will attract capital in virtually all economic conditions here. We continue to progress the LP drop-down strategy. We, on a conveyor belt basis, where we're extracting cash instead of paper for those assets. In the last year, we completed the drop-down of 30%, the remaining 30% of Bison, the remaining 30% of GTN, and we just announced the PNGTS drop-down, which is expected to close near the end of this year. In terms of dividend growth, we are comfortable extending the 8%-10% guidance to the end of the decade here, again, supported by the base business, clear, visible near-term growth, and extremely healthy coverages. I just want to spend a couple minutes here on the key risks embedded in the company. From a volume perspective, the bulk of our business is cost-of-service regulated businesses or long-term take-or-pay contracts. Where we do have volumetric risk is in two principal places. Keystone south of Cushing which is effectively the pre-build for Keystone XL, where there is capacity that is sold on a shorter-term basis there. Within our U.S. pipelines group, there is recontracting from time to time, but there is a portfolio aspect to that, where volumes tend to shift from one system to the other. Great Lakes would be the one where we do have the most volumetric capacity available at this point. On the commodity price side, in three specific regions is where you'll find our commodity price exposure. In Alberta Power, we have 1,700 megawatts of coal-fired generation, lowest on the dispatch curve. For every CAD 1 Alberta Power prices move, it's about CAD 10 million of EBITDA. In the Northeast U.S., we have outright exposures in New England, primarily associated with 550 megawatts of Renard River Hydro. We acquired that in 2005 from NEG's bankruptcy for CAD 900 a kilowatt. It's a very low-cost power in that region. For every CAD 10 New England prices move in terms of outrights, it's about CAD 17 million of EBITDA to the bottom line. At Ravenswood, we own the largest power plant in New York City, 2,800 megawatts on the East River. It is primarily a capacity price exposure there. For every CAD 1 annual capacity prices move, it's about $25 million U.S. to EBITDA. Lastly, on the storage side, we have about 120 Bcf of unregulated gas storage in Alberta. For every CAD 0.10 storage spreads moves, it's about CAD 9 million of EBITDA. We actively hedge these with long-standing marketing and trading businesses to, again, add margin and reduce the volatility of those exposures. On the counterparty side, on the long-term contracting side, much of our gas business where we do have contracts is with LDC utilities or in the case of Mexico, with CFE, which is essentially quasi-sovereign credit in that country. On the oil side, it's comprised primarily of the blue-chip producers and integrateds. On the power side, it's the likes of OPA, Hydro-Québec, and Salt River Project. Karl touched on the cost-of-service exposures, where we are seeing some stress and small defaults is on the NGTL system. Where we are seeing those defaults, that capacity that's freed up is in high demand. If there is any counterparty loss in that system, it is socialized amongst the rest of the shippers through the cost-of-service mechanism, subject to our having acted prudently. In terms of interest rates, I mentioned we're predominantly fixed-rate financers. If rates do rise, our cash flow from operations is fairly immune to interest rates in the near term. Again, we have the long-duration fixed portfolio. We have significant pass-through capabilities on interest rates in our cost-of-service-regulated systems and on the likes of our LNG projects. In some cases, we actually benefit from rising rates in terms of regulated ROEs. We have $20 billion of U.S. dollar-denominated assets, and included in that is our Mexican business, which revenues are paid in U.S. dollars, so its functional currency is U.S. dollars. We have a long U.S. $550 million after-tax position after natural hedges in the form of U.S. dollar debt. We actively hedge that on a one-year rolling forward basis. For every dime you see move in the currency, it's about $50 million-$60 million to the bottom line. Included in that $550 million is $100 million after-tax of U.S. dollar capitalized interest for Keystone XL. We are seeing a tailwind in FX right now. Hedges that were put on one year ago in the 110-115 range are now being reestablished in the 130 range that we're seeing today. Just turning to the financing program for 2015. CapEx this year should come in around CAD 5.2 billion. About CAD 2.8 billion of that is Canadian regulated gas pipelines. About CAD 1.4 billion in the liquids business and CAD 0.5 billion in energy and as well in other, including capitalized interest. We also refinanced CAD 1.8 billion in maturities this year. The funds from operations after dividends will amount to about CAD 3 billion, which covers about 60% of the CapEx program this year. We've had a fairly diverse, in some cases, innovative financing approach this year. Just walking through the bar chart from left to right. We completed the dropdown of the remaining 30% of GTN in April for $260 million. We issued a hybrid security in the U.S. capital markets in the second quarter for $750 million. It's a 60 non-call 10 product that attracted 50% equity credits and at a coupon of about 5 5/8%. In terms of preferred shares, we issued CAD 250 million of preferreds here in Canada in February at a record low rate of yield of 3.8%. We reset Series 3 this year, which is the CAD 350 million outstanding from the 4% range down to the low 2s. We have another similar one coming up here in January that's currently a 4.4% yield but should reset in the 250-260 range. In terms of senior debt, we did four U.S. dollar-denominated issues totaling $2.9 billion. The unique one was the $750 million issue into the Taiwanese insurance market, which was diversification of a funding base and pricing that was basically through the U.S. domestic pricing. We've challenged the finance group to try and get something done into North Korea next year. Any bankers in the room here, we look forward to your pitch books on something in that product going forward here. In Canada, we did CAD 1.1 billion of term debt. That was all for the NGTL system rate base. All in terms of funding, about CAD 6 billion this year. Average term, roughly 20 years, at a yield of 3.5%. When you are looking at margin, it's not just revenue, it's cost, and that's a pretty attractive blend of financing there. You can see the total adds up to more than the needs for 2015. We enter 2016 with about CAD 1.8 billion of pre-funding done. We have a heavy maturity profile in early 2016, and we also expect to close the Ironwood acquisition at that point in time. Just looking at the portfolio of near-term growth. I think we've shown a proven ability to continuously replenish this portfolio here, and again, announced about CAD 2 billion of projects since early October. Collectively, looking at this portfolio right now, CAD 13 billion of projects that we expect to complete through 2018. Just under half of that is Canadian-regulated rate base. About $0.5 billion of U.S. growth investment, mainly on ANR. $2 billion U.S. into the Mexican pipelines, CAD 3 billion into liquids, CAD 1 billion into the Napanee project, and just under $700 million U.S. for the Ironwood acquisition. We describe these as a universally normal course permitting and construction risk, which is quite refreshing. Revenue streams, as you see at this chart, are long life with limited variability and a fairly good diverse set of counterparts here. In terms of cash left to spend on this portfolio, we've spent CAD 3.5 billion to date on the CAD 13 billion program. When you factor in foreign exchange, it's about CAD 10.4 billion to complete the construction of this list here. Over the next three years, we see capital expenditures of about CAD 14 billion. CAD 10.4 billion to complete the growth projects in the previous slide. About CAD 2.5 billion in maintenance capital. About CAD 650 million in capitalized interest associated with these projects, and about CAD 400 million in development costs on our big major projects, much of which we expect would be recoverable if they don't actually proceed. On the maintenance capital side, as I mentioned, CAD 2.5 billion. About 40% of that is Canadian rate base, Canadian regulated pipes, which is somewhat front-end loaded. We had stepped up our integrity programs a couple of years back, and that program continues to run here, so heavier in the front end of this three-year profile than at the back end, again, into the rate base. Run rate of maintenance capital should normalize in 2018 period onward in the CAD 700 million-CAD 800 million range going forward. Capitalized interest, I mentioned there's CAD 650 million embedded in the capital program here over these three years for the projects on the prior slide. We're assuming a 5% rate for capitalized interest, and we are excluding Keystone XL in that calculation. Keystone XL is about CAD 180 million of capitalized interest in 2015. Development projects, as I mentioned, CAD 400 million, mainly associated with bringing Energy East to its permitted stage and the LNGs to final investment decision. Again, largely recoverable on the LNGs or ultimately into rate base as they proceed. Breaking this down year by year, about CAD 7.3 billion of CapEx in 2016, CAD 4.7 billion in 2017, and CAD 2 billion in 2018. The funding for that, again, about 60% of this would come from internally generated cash flow after dividends. About CAD 8.5 billion would be sourced from that. That includes a dividend growth rate of 9%, middle of the 8%-10% range. We have CAD 4.5 billion of LP drops included in this period. The LP is a strategic financing vehicle for the company. It allows us to extract and recycle equity capital, but still control assets that are strategic to our overall portfolio. We're committed to vending assets in there on a systematic basis. PNGTS was announced here recently, again, should close near the end of this year. The objective here, again, is to extract cash versus paper from the LP. The LP's capacity is probably in the USD 1 billion-USD 1.25 billion a year range, and that capacity will grow as the LP's size grows. In terms of cadence of drop-downs, two things that'll be clear factors here would be TransCanada's financing needs and the market conditions, including the LP's unit price. This is not something that we will force. We have many other financing levers we can pull, but we do see it over time as being a very attractive vehicle for us to finance our overall consolidated growth program. On the balance sheet side, we see about just under CAD 1 billion of net new financing. There's also about CAD 6 billion in maturities that'll occur over this time frame here. The mix of this financing will depend on our subordinated capital needs as to how we would include preferred shares and hybrid securities and the like in here would depend on market conditions and then what else transpires in terms of our portfolio. This would all be done within the constraints of an A-grade credit rating and no specific bias as to product or term or market. Looking at the large capital projects from a post-development standpoint, again, I reiterate they are all very credit-supportive projects. It would be, in our view, a high-grade problem to have to finance an Energy East or a Keystone XL or any of the LNG pipelines. Again, the nature of these projects gives us great comfort in terms of attracting capital to them. As Alex outlined, development cost is minimized. If these projects never did ultimately proceed, we would expect recoveries north of CAD 2 billion from the invested capital we have in them to date. There we go. As I mentioned, about CAD 6 billion of debt maturities over the next three years. Approximately USD 4 billion of that is in U.S. dollars and just over CAD 1 billion Canadian. We consider this fairly normal course. We have debt shelves in place. Again, multiple markets, products, terms, investor bases to source that capital from. From a liquidity perspective, liquidity is excellent, backed by CAD 6 billion of credit lines. Two commercial paper programs going to three here shortly. We expect to establish a U.S. dollar-paid commercial paper program for TCPL in the coming months here. Liquidity has been battle-tested before. We are one of the few corporates in the financial crisis that didn't actually draw its bank line. We've been through the fire. In terms of levers to pull, internal cash flow, first and foremost, is resilient and very predictable. After that, senior debt, we look to source within the constraints of an A-grade credit rating. What we're looking for here is 15% FFO to debt, three times FFO to interest is the key benchmarks over the cycle for senior debt. We have historically not done a significant amount of project financing. That said, we would explore it in three specific spots going forward. The LNG projects are of a nature where the cost of project financing may be very similar to on-balance sheet. Bruce, because of its unique nature, is something we'll explore there. Mexico, if we get large enough to cap sovereign risk, is another place where we would evaluate project financing. Subordinated capital in the form of preferreds and hybrids. We see pushing those products to about 12% of capital structure before you start seeing some diminishment of equity credit accorded to them. We're currently at 9%, so the headroom there is probably in the CAD 1.5 billion range for the next year or so. Portfolio management noted primarily in the form of LP drops between CAD 4 billion and CAD 4.5 billion. If we do get to a point where we need equity, it's last on the list. A DRIP program is something that actually fits nicely with a multi-year construction program, and you can turn it on and off. Our history was that in the past, at a 2% discount, you could get 35% participation on a DRIP. That's something that if one of these big projects did move ahead, we would evaluate. In terms of discrete equity, that is last on the list, and we would certainly look at either bringing in partners or selling assets before issuing equity going forward. In terms of partners, the LNG projects is one spot where we would contemplate selling an ownership stake in those pipelines. We continue to receive many inbound calls of parties wanting to co-invest in our many projects. I think that avenue is wide open to us. Other levers we could pull, the Keystone Pipeline is a qualifying asset for U.S. MLP purposes that generates $750 million a year of U.S. domiciled EBITDA. That could be a healthy source of capital if need be. In terms of outright asset sales, we'd be unemotional about that. We have no psychological aversion to that. It'd all be weighed at the point in time where we had to make a decision whether to recycle capital. Again, all through the lens of per-share metrics. Looking at the EBITDA build here, Alex gave a little more granularity on this, but we see EBITDA growing from the CAD 5.8 billion range in 2015 to CAD 7.2 billion in 2018. That's a 24% over these three years. All the business lines increase in terms of EBITDA. On the gas side, about CAD 950 million. Mexico is CAD 375 million of that. U.S., CAD 275 million. Canadian rate base, CAD 300 million. About CAD 200 million on the liquid side, that is Northern Courier, Grand Rapids coming online. On the energy side, about CAD 300 million driven by Ironwood and Napanee coming on. We are introducing comparable distributable cash flow as a financial measure here today. In our view, earnings do matter, but this is a supplemental measure of performance that defines cash available to common shareholders before capital allocation. We think this is an important data point and something that we factor into our thinking as we look at capital allocation, including dividend policy. It is a fairly simple derivation. It is funds from operations, ex working capital changes normalized for non-comparable credits and charges. From that, we subtract distributions to third parties. That would be mainly third-party LP unit holders and preferred share dividends. We subtract maintenance capital, which cost necessary to preserve the operating ability of our fleet. We see distributable cash flow growing from CAD 3.2 billion in 2015 to CAD 3.9 billion area in 2018. That is a 7% CAGR, driven by the EBITDA build and some decline in maintenance capital, probably in the CAD billion area this year down to, CAD 700 million-ish in expectation in 2018. We have excluded Keystone IDC or capitalized interest, post-2015 in this calculation here. We will begin reporting this quarterly and on a per-share basis with a little more granularity. This is probably the most convoluted titled slide I have had in several years. I am going to call this my Saskatchewan earnings cliff. Flat as far as the eye can see. The purpose of this graph here is to just show you the resiliency, the long life, and the quality of the EBITDA and cash flow streams embedded in the company today. The assumption here is we complete our CAD 13 billion capital program that has been outlined for you this morning, and we do nothing else but expend maintenance capital over the next decade. What you can see is locked in is about CAD 5.6 billion of EBITDA in 2025, supplemented by another CAD 1.1 billion of largely current run rate EBITDA associated with market-facing businesses. Out in 2025, we see EBITDA from the Canadian rate base assets of about CAD 2 billion. On the liquid side, there is about CAD 1.2 billion from the contracted Keystone volumes as well as Northern Courier and Grand Rapids. On the U.S. pipeline side, about CAD 900 million Canadian equivalent, batched up by things like 23-year contracts in the Southeast Mainline and ANR, strong contracts in GTN, North Baja, Tuscarora, and the like. Mexican assets are all under 25-year contracts, U.S. dollar pay. There is CAD 600 million there, and there is about CAD 900 million we have included here on contracted power. We have, for purposes of this analysis, left Bruce at CAD 300 million as we remain optimistic we will get that transaction over the finish line sometime in the near future. About CAD 5.6 billion of clear line of sight EBITDA through 2025. In the orange bar, we have EBITDA that is subject to some variability. We have included USD 250 million, CAD 300 million Canadian equivalent of U.S. pipe EBITDA. Much of that we would be very confident that we can recontract, but it is subject to recontracting over this timeframe. We have about CAD 250 million associated with Keystone spot volumes and about CAD 550 million associated with merchant energy, although some of that I would posit is predictable in the form of capacity payments at Ravenswood, Runner River Hydro, Ironwood, and Gas Storage and the like. You add all this up and it's CAD 6.7 billion of EBITDA from these bars out to 2025. From that, we would expect to grow the base through new investment, probably have CAD 5 billion in investment capacity, post-2017, 2018 timeframe, and that's factored into the blue bar at the top here. With that, we are quite confident in our guidance of 8%-10% dividend growth at least through 2020 here. Again, the base business, the near-term growth, the resiliency of the cash flows, and the growth of those cash flows in the near term here. You can see on the right-hand side, the distributable cash flow coverage is also very robust, currently in the area of 2.2 times. I am assuming a 9% dividend growth rate mid-range of the 8%-10% over this timeframe, and you get out to 2.0-2.2 times in 2020. The swing factor there largely being the current versus deferred tax split. If you stop building things, you have less tax shelter. If you keep building things, you have more tax shelter effectively. Again, very healthy coverages on the dividend. Just before I wrap up, a few comments on capital allocation and how we look at that going forward. First and foremost, sustainable dividend growth as we have outlined for you this morning. Second is new investment opportunities. Beyond the CAD 13 billion that we have today, we have the CAD 35 billion of large-scale commercially secured projects. We continue to evaluate opportunities in the core businesses and geographies, and you have heard mention of more Mexico, more NGTL, potentially a Bruce deal here this morning. Just a long-term track record of finding ways to replenish that small to midsize growth portfolio over time. Bluntly, to the extent capacity exists, our own shares are compelling at this level too as a place for the company to invest its capital. There is a circularity to financial strength in all of this to maintain that A credit rating and the ability to source capital through all economic conditions here. If we cannot find opportunities within our risk tolerances within these business lines, we will accelerate the return of capital to shareholders, either through increased dividends or shrinking the balance sheet in line with an A credit rating. In closing, just to touch a couple of key themes here. This is a resilient and proven business. 13% annualized return to shareholders dating back to the year 2000. We seek to deliver long-term shareholder value, but not at the expense of short-term returns. We have a foundation of EBITDA that goes out well over a decade with confidence here. We have got a proven ability to navigate through various events and changing dynamics in the industry as we have proven over time. Visible near-term growth, a CAD 13 billion portfolio with not one but four transformational projects on top of that. We have the financial strength to execute on all this. The story is understandable, and the strategy is very enduring. We will be disciplined in capital allocation, all looked at on a per-share basis. You can look forward to 8%-10% dividend growth through the end of this decade. With that is the end of my slides, and I will be happy to answer any questions. Go ahead, Andrew. Don, you didn't mention anything about the cost savings and the corporate restructuring that Russ mentioned earlier on, I think Alex also mentioned. What's the economic impact of that Q4? Also looking into 2016, how much savings do you think you'll generate from the pretty significant restructuring activities? Yeah. As I mentioned, we are right in the middle of this right now. We can't actually quantify it for you today. We'll be in a position to do that when we release year-end results. It'll be split into three components. There's a capital element, just better execution of capital programs. There's an element that will flow through to our customers, and then there's a P&L element. Other than that, at this point, I really can't quantify it with any great detail right now. If I may, I'll just ask another question, just in relation to the IRRs you're expecting on projects. Any significant changes in expectations on IRRs? I think over the years, depending on the investment, you've been looking six to nine for less risky things, and then nine to 11 on more risky projects. Does that still hold true? Yeah, we haven't really seen any gravitation away from that. Patrick Kenny, National Bank. Just on the maintenance capital, Don, the CAD 700 million-CAD 800 million run rate I guess sounds like a big number, relative to an CAD 80 billion asset base by 2018, I guess it would imply a 100-year useful life for the portfolio. I guess I'm just wondering how real is that run rate, or are there some lumpy maintenance capital expenditures still to come a few years out? It varies. I would say that of the CAD 75 billion, CAD 80 billion fleet that's out there, much of it is fairly new vintage at that point in time when you look at how much has been built over the past few years. It's the nature of a lot of this infrastructure. Once it's built, its maintenance capital requirements are fairly minimal. These things are depreciated on average over 40 plus, minus years for accounting purposes. We'd see the maintenance numbers ebbing and flowing depending on, like you heard this morning on ANR, now that we're seeing the system fill up again, we are having to spend money to catch up from maintenance that wasn't required in past years. Of that amount, I would also note about half of it is going to be for Canadian regulated pipes, which is effectively growth capital into the rate base. Any other questions for Don? Oh, sorry, Robert. Just give us a second. Don, just to clarify what's in the distributable cash. Similarly, yield perspective spread between our dividend yield and the Canadian government handled bond is at about a five-year high. Despite what has been very strong past performance, a positive outlook for the future, and our accelerated dividend growth expectations versus where we were 5 years ago. While the threat of rising interest rates may play a role in widening the spread, I'd note that rates continue to be near historical lows, and it's not possible to take advantage of that. We can stress again rentals are in our shareholders' hands to capture significant share price appreciation. At the end of the day, we recognize that we can't control how the investment community values us on a week-to-week or month-to-month basis. Our job is to continue to deliver strong performance Performance while carrying out our business in a responsible manner with the utmost attention to safety and reliability. For the last 15 years, we've grown our common share dividend at a compound average rate of about 7%. We look forward to building on that track record of dividend growth over the next 5 years by growing the dividend at an average annual rate of 8%-10%. This combines, as I said, with 5% current yield, provides our investors with a very attractive risk-adjusted 13%-14% return with potential upside if we return to historic trading multiples. What I can tell you is that our intent is to remain disciplined, and that we will continue to grow our company in much the same way as we have over the last 15 years, for the next 15 years. Thanks again for joining us today. We very much appreciate your interest in TransCanada. Our team looks forward to joining you over lunch. I'll turn it back to David, and I think he'll get to the last logistics of the day, and then we'll get you fed. Thank you again for joining us today. Just further to Russ's comment, again, we very much appreciate your time today. I know you've all got busy schedules, and we appreciate you taking the time out. Just as a small token of our appreciation, just for all of you, there should be on the inside of your front cover of your binders, a charity gift card. If you just follow the instructions associated with that, you can actually make a donation to the charity of your choice. We think that's in keeping with the needs of many others out there who are a little less fortunate. With that concludes our morning, and lunch will be served next door here momentarily.

Data Source: Quartr Last updated: Nov 17, 2015

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