All participants, please stand by, your conference is ready to begin. Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2017 First Quarter Financial Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President-Investor Relations. Please go ahead, Mr. Moneta.

Thanks very much and good afternoon, everyone. I'd like to welcome you to TransCanada's first quarter 2017 financial results conference call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Karl Johannson, Executive Vice President and President, Canada and Mexico Natural Gas Pipelines and Energy; Paul Miller, Executive Vice President and President, Liquids Pipelines; Glenn Menuz, Vice President and Controller; Stan Chapman, who is recently appointed Executive Vice President and President U.S. Natural Gas Pipelines, couldn't join us today, but will participate in all future calls. Russ and Don will begin today with some opening comments on our financial results and certain other company developments. Please note that a slide presentation will accompany their remarks. A copy of the presentation is available on our website at transcanada.com. It can be found in the Investors section, under the heading Events & Presentations. Following Russ and Don's remarks, we will turn the call over to the conference coordinator for questions from the investment community. If you are a member of the media, please contact Mark Cooper or James Millar following this call and they would be happy to address your questions. In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations for your detailed financial models, Stuart and I would be pleased to discuss them with you following the call. Before, Russ, begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities Exchange Commission. And finally, during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, comparable earnings before interest, taxes, depreciation and amortization or EBITDA, comparable funds generated from operations and comparable distributable cash flow. These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. They are measures used to provide you with additional information on our operating performance, liquidity and our ability to generate funds to finance our operations. A reconciliation to the nearest GAAP measures is included in the appendix. With that, I'll turn the call over to Russ.

Thanks, David, and good afternoon, everyone. And thank you very much for joining us on a Friday afternoon. As I've highlighted in the past and again earlier today at our Annual Meeting, Trans 2016 was truly a transformational year for TransCanada. Our portfolio of high-quality energy infrastructure assets performed very well and our long-term strategy, financial discipline enabled us to undertake unprecedented growth that will reward our shareholders for many years to come. We continue to build on those accomplishments here early in 2017, evidence of that can be seen in our first quarter record financial results, which support our board of directors' decision in February to increase our quarterly common share dividend to $0.625 per share, that equates to $2.50 per share on an annual basis and represents a 10.6% increase over the dividend in 2016. During the first quarter, we also continued to advance our $23 billion near-term capital program, spending approximately $1.8 billion. In aggregate, this portfolio of commercially secured and rate regulated projects remains on time and on budget. In addition, we completed the US$920 million acquisition of Columbia Pipeline Partners. To help fund our capital program, we completed $2.6 billion of external financing across the capital spectrum on very compelling terms and initiated a US$765 million drop down to our U.S. MLP. And finally, we continued to advance a number of other strategic initiatives that will enhance our competitiveness and position us for additional long-term growth. I'll touch on each of these developments in the next few slides, beginning with a brief review of our first quarter financial results. Excluding certain specific items, comparable earnings for the first quarter of 2017 were $698 million or $0.81 per share, an increase of $204 million or $0.11 per share over the same period last year. That equates…

Okay. Thanks, Russ, and good afternoon, everyone. As outlined in our quarterly report to shareholders issued earlier today, we reported net income attributable to common shares in the first quarter of $643 million or $0.74 per share, compared to net income of $252 million or $0.36 per share for the same period in 2016. Per share amounts include the dilutive effect of issuing 161 million common shares in 2016, plus additional shares issued through the dividend reinvestment program in the first quarter. Our results include a $24 million after-tax charge for integration-related costs associated with the Columbia acquisition, a $10 million after-tax charge for the costs related to the monetization of our U.S. Northeast power business, a $7 million after-tax charge for maintenance of Keystone XL assets, and a $7 million income tax recovery related to the realized loss on a third-party sale of Keystone XL assets. First quarter 2016 results included $176 million after-tax impairment charge on the carrying value of our Alberta PPAs, a $26 million after-tax charge related to costs associated with the acquisition of Columbia, a $6 million after-tax charge related to Keystone XL costs for the maintenance and liquidation of project assets and a $3 million after-tax loss in the sale of TC Offshore, which closed in March 2016. Excluding these items and specific risk management activities, comparable earnings for first quarter 2017 rose by $204 million to $698 million or $0.81 per share compared to $494 million or $0.70 per share for the same period last year, a 16% increase on a per share basis. Turning to our business segment results on slide 13, in the first quarter comparable EBITDA from our five business segments was approximately $2 billion, $475 million higher than the same period in 2016. The increase was largely driven by…

Thanks, Don. Just a reminder, before I turn it over to the conference coordinator for questions from the investment community, we ask that you limit yourself to two questions and if you have additional questions, please reenter the queue. With that, I'll turn it back to the conference coordinator.

Thank you. We will now take questions from the telephone lines. The first question is from Rob Hope of Scotiabank. Please go ahead.

So, good afternoon. Thank you for taking my calls. I was hoping – or my questions. I was hoping we could first touch on Keystone XL. Could you provide an update on the key work streams there and how your discussions have been going with potential shippers there, especially in the light of an uncertain D.C. election?

Rob, it's Paul Miller here. The key work streams I guess, there's two primary work streams that being securing the commercial support for Keystone XL and the Nebraska Public Service Commission approval for the route through that state. In regard to the shipping contracts, we're making progress with our existing shipping group, as well as new entrants, as they work through their analysis and the documentation. A lot has changed since we were first denied the permits here in 2015 in regard to crude oil pricing and supply and various competitive alternatives, so they continue to work through that and I anticipate it will take a couple of months yet before we sum up our commercial support. On the Nebraska Public Service Commission, we filed our application back in February. We are going to various open houses, one most recent here was on Wednesday of this past week. I was very encouraged by the format and structure, and the organization of the process by the Public Service Commission. We saw participants from both sides respectfully convey their positions, so I think it will be a very robust exercise. I would anticipate a second open house here in the next month or so, and finally we would see the hearings conducted in early August in Nebraska with the decision received by the end of November.

All right. That's helpful. And then I believe the messaging on the Q4 call was that even with a Nebraska decision late in 2017, the project may not necessarily start construction until well into 2018. Is that still the expected timeline there or could you move that forward or backwards?

No, that continues to be the timeline. We will work through Nebraska. We will work through our commercial negotiations with the shippers, and once we have certainty on both, in early 2018 I would anticipate we would start staging the project as far as securing what material we still have to secure as well as the contractors, and that exercise will take upwards of six to nine months. So I would not see construction started until Q3 timeframe of 2018, and construction would take probably little over two years.

All right. That's helpful. Thank you.

Thank you.

Thank you. The following question is from Linda Ezergailis of TD Securities. Please go ahead.

Thank you. Just wanted to maybe shift focus a little bit on some of the elements of your financing strategy. With respect to your U.S. Power Marketing business, will that be sold in Q2 as well and if not, how might we see it to run down over time as it's still about a $400 million of value that will be kind of realized over the next couple of years?

Hi, Linda. It's Don here. Yes. It's under a couple of times, here, we continue to actively look at the sale process as well as full monetization over time, it's a dual path here. We expect to realize proceeds, as we'd indicated before in that $400 million range and that will crystallize over time. We've seen a little bit of that come through now, that has been applied to the bridge loan. But generally, really no change from what we indicated earlier. But we don't have definitive line of sight to whether that will be a monetization over time or a single point sale.

Okay. Thank you. And maybe just a question on the $23 billion of projects; for some of the larger initiatives, what would be kind of some of the key potential bottlenecks? And I guess, I'm specifically thinking of, with some of the changes going on at FERC, how long can that drag on before that starts to affect the timeline of the projects?

Yeah, Linda, it's Karl. I think, we talked about this on the previous call that, with the lack of quorum there, and I see they lost another board member, so the lack of quorum is not getting better. We have three – what I call, three significant projects in the queue, they are going through the regulatory process right now. Our expectation – we're expecting earlier to get those – the FERC approvals by the end of June. Realistically, if we can get them by the end of summer, I think, we are in pretty good shape, but quite frankly if they can't get a quorum or we can't get them by the end of summer, we're going to have to start revisiting the in-service dates on those, but we still have several months yet to get them, so we are still optimistic, we'll be able to get them by the end of summer here.

Great. Thank you.

Thanks, Linda.

Thank you. The following question is from Praneeth Satish of Wells Fargo. Please go ahead.

Thanks. Just one quick question for me. So, can you just remind us, again, your ability to recover development costs for the West Coast LNG projects? I think in the past, you talked about $900 million in total, and I guess, just given recent announcements, would you expect to collect this and if so, what's the timing?

Hi. Yeah, this is Karl, again. Yeah, we have provisions in our agreements with the sponsors of those projects, that we can collect all of those monies. There are certain dates, in which we can call them back from the companies, which we haven't done at this time, but we are quite confident that we can get those, those monies back in due course. Now, having said that, I would just say that, both of our sponsors are still quite optimistic that they will ultimately provide an FID, and we still are doing a little bit of work on the projects, but the work has slowed down quite a bit, and your number of $900 million is approximately right.

Okay. Great. Thank you.

Thanks.

Thank you. The following question is from Ben Pham of BMO. Please go ahead.

Okay. Thanks. Good afternoon. Actually, this question is for Russ. Just thinking about some of your comments about organizational structure, you've had some pretty dramatic changes, the VP director level last year and more recent – the senior levels more recently. I'm just curious as you've gone through that process and seeing Alex leave here and more curious about how you got to the decision of not needing a replacement for him. And is this – can it be now, that structure, that position, you're pretty comfortable with that for over a next few years?

I guess, maybe I'll start with. Yes, I'm very comfortable with the structure of the organization. All of these things are natural evolutions at a company that's grown as considerably as we have over the last number of years. Today, as I mentioned in my prepared remarks, we have five significant platforms for growth. These are all sizeable businesses that produce $1 billion to $2 billion each of EBITDA. Each of those has a president in-charge of it that has now responsibility for all aspects of its business. We reorganized and decentralized here over the last 24 months. So they're responsible for operations in all of their embedded services, as well as capital projects. So, a bit different sort of approach than we've taken in the past. As the company's grown, we've decentralized to put decision rights and accountability in the hands of folks that are closer to the action and can make better and more efficient decisions. So, the changes that have been made or what I call natural evolution, we have a very, very strong bench and depth in our organization. And so we will continue to evolve our organization as our business changes, but as I look at it today, the change that we announced here most recently with Stan Chapman being promoted to Executive Vice President and President of U.S. Gas is just the reflection of the size of that business. Half of our employees are now in the U.S., half of our EBITDA, half of our revenues. It's natural that we need a person based in Houston that is part of our executive leadership team. Stan, as I said, has got 30 years of experience, so deep bench and natural evolution of management. And, I guess, in terms of looking forward, you can expect this to continue to evolve our management team to meet our business. And as I said, I'm very proud of the accomplishments of the folks that have left, but equally proud of the bench that we have and the strength of our team to evolve with our business.

Okay, great. And maybe this question is for Don and some of the commentary on the TC Pipes and the strategy there. And I'm just wondering beyond the $1 billion target you've highlighted, just curious about some other things that you look at when considering drops going forward? Is it looking at accretion to the TRAP or can that be liquids, rather than just gas drops? Maybe just share what else that you look at when considering drops to TCP.

Yeah. The inventory is pretty deep, when you look at what's left of the legacy TransCanada assets that are qualifying assets, including the balance of Great Lakes, some of the stuff that's come in with Columbia such as Millennium, the Columbia portfolio itself as it is built out. So the inventory of gas assets is very large. Liquids Pipes are a qualifying asset for MLPs. That said, I'm not sure they would be fully described as mature assets, given the opportunity to potentially build out XL here. So, we don't have any specific color coding of what sequencing or when this might happen, but the first point I'd make is that there is a huge inventory of stuff that could ultimately go into TC Pipe LP. Our thought process as to when and what goes in, there's a number of factors that go into that. Firstly, it's driven by our financing needs at big TransCanada. It is a financing vehicle. I'll speak about other growth possibilities for it in a second here, but the financing needs at the parent company are a pretty important component of this. In terms of the price at which we set these drops, it is a balancing act that we don't want to be transferring value from one shareholder base to the other at any point in time. So it is always a balancing act. In terms of moving forward on that, the Pipe LP drops, what we do is we compare them to other forms of capital that we can raise and things in that camp would be, say, preferred shares here in Canada, probably something in the mid-4s after tax right now. Hybrid securities, which is a very attractive vehicle right now for us, probably something in the 5% area pre-tax, high 3% area after-tax, additional portfolio management and the like. So, the MLP dropdown would be weighed against those factors. Other key things in that would be what is the unit price for the LP and what is the capacity of the LP. So probably a long-winded way of saying, there's a whole lot of moving parts here. We do see it as an important vehicle going forward from a financing perspective. As well, we would like to grow the LP through high-quality but smaller scale acquisitions if we could going forward. We will do that on a disciplined basis, but stuff that may not move the dial at the parent company that might be a real good fit for the LP is what we'd be focused on there.

Okay. Can I follow-up? You're always looking at accretion at the TCP level, but then when you bring it back to corporate side, maybe on paper, it's neutral to EPS, but then when you factor in opportunity cost of financing, it is accretive to you overall?

Yeah, it's a fair comment. We are always looking at share count at the parent company, so if the LP issues third-party equity, that is treated as dollar for dollar equity in calculating our credit metrics at the parent company. So it's avoided cost of equity and avoided share count increase at the parents. So that's a pretty important factor here.

I think as well, Ben, if you – as Don said, I mean, those are our criteria, but all the transactions that we've done to date have been accretive to the parent TRAP. And the other piece that you have to take into consideration is the distribution splits at the LP level in calculating the accretion of the dropdown to TRAP. So, overall, we look for accretion. But as Don said, primarily driven off of our financing needs and how that cost of capital compares to other cost of capital. But to-date, we've been pretty fortunate that everything that we've done, in our view, has been accretive.

Okay. All right. Thanks, Russ. Thanks, Don.

Thanks, Ben.

Thank you. The following question is from Robert Kwan of RBC Capital Markets. Please go ahead.

Good afternoon. If I can just ask about some potential on the NGTL expansion. First, whether there's some color you can give on the Westpath, open season, but as well as it relates to the Mainline LTFP deal, what do you see in terms of additional investment as you think about expansion for delivery service as well as expansion of upstream James River.

Robert, it's Karl. Yeah, as you've obviously noticed that this week we put out a new open season for our Westpath deliveries, up to 400 million a day. We'll see how that open season comes, but we do have two things, we've got customers asking for more delivery service which this open season has meant to take care of them. We have a queue of customers looking for a receipt services, which is still up in – upstream in the Montney area in the oil or the gas – I think in the gas shale area. So, we will assess the response to the open season we put out, and we will assess the amount of receipt services that we need to put in and we will be back to the market shortly thereafter with our plans. I can say, it's probably if we have success on this particular open season, and with the resulting new receipt service that brings on, it will be a $1 billion-plus type of expansion starting – construction starting in probably late 2018, early 2019.

Okay. And then – Karl, was that just for the Westpath, or did that include the Upstream James River as well if any delivery expansion you might need into Empress?

Yeah. No, that would include the Westpath in any resulting new receipt services that comes along for the Westpath. So that would not be an expansion to the East Gate at this time.

Okay. And did you need anything on the East Gate to serve the LTFP deal?

No, not at this time. We have capacity for the East Gate. Our volumes aren't growing large enough that I would expect, at some point in the future, we might need some extra compression support for the East Gate, but we certainly have enough right now for the long-term fixed pricing, and some future growth of East Gate deliveries beyond that.

Got it. Okay. And if I can just finish here with Keystone XL. The commentary about substantially similar customer support. I'm just wondering is that both volumes and toll, and then on – as for cost, Russ, you mentioned at the AGM, that the cost can actually be a little bit lower. I'm just wondering was that statement around the gross cost or is that net inclusive of the write-down?

I'll start with the first one is, it will be beyond the gross cost, and certainly my job is to push our team to make this as economic as possible for our shippers and, certainly, that's the directive that I've given to Paul and his team and they are working hard to make that happen. I'm optimistic it can occur. With respect to the contract, maybe I'll turn it over to Paul, and he can talk about where we're at on the contract.

Sure, Robert. We do anticipate, ultimately, while we are targeting to secure the volume – contracted volume we had previously as we move – potentially move forward with Keystone XL, I do anticipate some of the current shippers will increase their commitments. I also anticipate some of the current shippers may decrease their commitments as they look at their total transportation requirement. I would also anticipate that we will introduce new parties into the shipper group. So the net result of this is we do anticipate to have contractual support similar to what we enjoyed previously, albeit amongst the different shipper group.

Okay. So just to be clear, roughly speaking, 90% of the capacity, a very similar total to what you had prior?

That's what we'll be targeting. Our goal is to fully contract XL, as you know, we have to set aside some capacity for the spot shippers and we'll certainly do that. And, our total will – our total remains competitive, notwithstanding the delay and we will with good CapEx, cost management, Russ talked about, we will keep our total in line.

That's great. Thank you very much.

Thanks, Robert.

Thank you. The following question is from Robert Catellier of CIBC World Markets. Please go ahead.

Hi. I was just hoping to get a little bit of follow-up on West Coast LNG and let's start with the North Montney request for variance. Do you see anything getting in the way there and what are sort of milestones when you expect an outcome there? And then, just secondly with respect to the success of Canadian LNG projects, can you comment on that both in an environment with an NEB government and without – so in other words, what's really holding these projects back, is it simply a question of proponents getting comfortable with the market?

Hi. This is Karl, again. So maybe I'll start with the North Montney. And we have put in our application for a variance review. What we are trying to do is ask the board to release a condition on our – approval we have already received for it and that condition is that the LNG goes ahead. We now have – we recently submitted that application for approval, we had one shipper in that, gas was fairly – was deem to go into the LNG terminals. Today, we have 11 shippers, one of which is the LNG proponent. We have 11 shippers that want to move gas into the markets right now, and they've also in very long-term agreement. So, we believe – the circumstances have change enough that this facility is not necessarily dedicated to any LNG facility, and we would – we're asking the NEB to recognize that and to lift that condition. The process for it right now is NEB has came out and ask for comments on the process to looking at it. That process can be another hearing or it can be just the NEB opining on it by themselves as to whether they want to accept the variance or not. They have suggested that they've – that through May and the first half of June, interested parties can submit their questions and concerns and positions, and that the board should respond as to what the process will be by the end of June. So, that's about as much as we know about the process, right now. On Canadian LNG projects with government – whatever government that is, I would remind you that both of these LNG projects have very, very strong support from both the aboriginal communities and local communities that they are in right now, and they're both fully permitted. So, I think they're both relying on FID decisions for the sponsors. I'm not – it's really difficult for me to comment on what a sitting government of any particular party would want to do with those approvals, but it strikes me that this is more of an economic situation right now that the proponents you're looking for and not a political one.

Okay. Thanks for that answer.

Thanks, Rob.

Thank you. The following question is from Patrick Kenny of National Bank Financial. Please go ahead.

Yeah. Good afternoon, guys. A quick question for Karl here on the gas storage margins. Now three relatively strong quarters in a row, just wondering if you can remind us of some of the positive market dynamics that are at play right now, helping out contributions, and then maybe to the extent you can, how you see the market for storage and the spreads through the summer and into next winter?

Yeah. So a couple things happening. We have had some good quarters of storage margins both in Alberta and down in the U.S. So I would say that this warm winter probably hasn't – it hasn't helped them a lot. We have quite a lot to fill in Alberta, for example. We have a lot of gas – leading Alberta with the long-term fixed price still to come in the fall. So, we may not get that storage filled up again. So, I would suggest that, what we have seen is probably what we're going to get maybe not better, but – it's not going to be a lot worse, but we do have some little bit of headwinds on that just because of the warm winter and the extra gas which we're taking out of Alberta would be a long-term fixed price. In the U.S., a bit of a different situation, although that the storage in the U.S. is highly contracted with LDCs, it tends to be a little bit more consistent. Certainly, on the ex-Columbia assets, it's very, very full with LDC contracts, and even on the old TransCanada assets, ANR specifically still one of the LDC contractor. So, probably less volatility there, less price sensitive storage there. So, the fundamentals of, I think, about storage right now is the surplus gas production. As the production does go up, you do need more storage, you do need – there is more need to manage volume swings, volumetric swings because, the gas is coming at you every day. So, we're still pretty satisfied with the storage business in TransCanada. We still think there is a need for storage. And then with the increasing gas price, we see the utility storage staying the same, if not getting better in the long-term.

All right. Thanks for those comments. And then just maybe a cleanup question on Columbia. I know Russ you mentioned that synergies are on track here as expected, but are you at the full $125 million run rate coming out of Q1 or you still need a couple of quarters to get there?

Patrick, it's Don here. We're not at the full $125 million right now, but we've got a healthy chunk of that in the first half of this year. So it will still be a ramp-up through the rest of the year, but we're on track for $125 million for the year, but not at a full run rate yet.

Got it. Thank you very much.

Thanks, Pat.

Thank you. The following question is from Nick Raza of Citi. Please go ahead.

Thank you, guys. Just a couple of quick follow-up questions. The Great Lakes Rate Case, how will be the rate case go with TransCanada contracting what's essentially a fairly large chunk of capacity on the system, do you sort of have any views on that?

Well, so a couple of – this is Karl, again couple of things on that. First of all, as you've obviously seen, we have filed with the NEB that we have completed a contract with Great Lakes to move approximately half of the volumes from the LTFP to Great Lakes. We did that, because the Northern going to – taking that volume over the Northern part of our Mainline system, and into the Triangle could not accommodate all of that volume going into Dawn through the Triangle, so that's why we have done that. Both the Mainline and Great Lakes are in rate cases right now. The Mainline, obviously, has to go get approval for the volumes – for the service that we're offering, and as part of that service, the board will be interested in the prudence of how we're splitting the volumes between our Mainline and Great Lakes. Great Lakes will be – is in a rate case, a regular five-year rate case, as we speak, right now. So it's very difficult for us to say, right now, A, what those approvals will ultimately look like, and what the rate cases on Great Lakes or the settlements on Great Lakes will look like as well. So, it's a little premature to start speculating on how we're going to come out of both of those rate cases. So, again, we'll have to wait and see as both of those rate cases gets settled or litigated.

Okay. Thank you, guys. And then just one final question. In terms of expansions for Iroquois and Portland Natural Gas, are there any sort of plans to do anything as now the assets are completely sort of in TC PipeLines?

It's Karl again. I think the short answer is, yes. I don't think the fact that they're in TC PipeLines has any bearing on whether there's plans on expanding them or not, but certainly if there is a demand for extra capacity to go down those facilities, us and TC PipeLines will be anxious to fill that demand. I can't tell you we have been in the market with PNGTS with the Portland system, marketing some capacity there, some increased capacity there for when the contracts roll of in 2018 and we have gotten significant interest. Not enough yet to get contracts signed and announce anything, but there is significant issue there. And of course once we sell PNGTS, then we will see we will need more capacity going down the Mainline and TQM and Eastern Triangle of the Mainline. So I think it's pretty much business as usual there. If we can't find more capacity, more customers willing to ship on our systems, we will accommodate them.

That's all I have. Thank you, guys.

Thank you. There are no further questions registered at this time. I'd like to turn the meeting back over to Mr. Moneta.

Great. Thanks very much. And thanks to all of you. We very much appreciate your interest in TransCanada and we look forward to speaking to you again soon. Have a great weekend. Bye for now.

Thank you. The conference has now ended. Please disconnect your lines at this time. We thank you for your participation.