Good morning, ladies and gentlemen. Welcome to the TransCanada Corporation 2018 Third Quarter 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 morning, everyone. I'd like to welcome you to TransCanada's 2018 third quarter conference call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Karl Johannson, President of Canada and Mexico Natural Gas Pipelines and Energy; Stan Chapman, President, U.S. Natural Gas Pipelines; Paul Miller, President of our Liquids Pipelines Business; and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com. It can be found in the Investors section under the heading Events. Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Grady Semmens following this call and he 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 re-enter 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 or your detailed financial models, Duane and I would be pleased to discuss some 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, I'd also point out that 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 comparable EBITDA, comparable funds generated from operations, and comparable distributable cash flow. These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. They are used to provide you with additional information on TransCanada's operating performance, liquidity and our ability to generate funds to finance our operations. With that, I'll turn the call over to Russ.

Thank you, David, and good morning, everyone, and thank you very much for joining us today. As highlighted in our quarterly report to shareholders released earlier today, we're very pleased to announce another quarter of strong results, which are expected to contribute to record financial performance in 2018. As outlined in the report, our CAD 94 billion portfolio of high-quality Energy infrastructure assets continue to profit from strong underlying market fundamentals and we are realizing the growth expected from our secured capital expansion program. Evidence of this can be seen in our comparable earnings of CAD 1 and CAD 2.82 per share for the three and nine months ended September 30, 2018, which supports our board of director's decision in February of this year to increase our quarterly common share dividend to CAD 0.69 per share. That equates to CAD 2.76 per share on an annual basis and represents a 10.4% increase over the dividend we paid in 2017. During the quarter, we also continued to advance CAD 36 billion of secured capital projects, which now includes Coastal GasLink, NGTL's 2022 expansion and Bruce Power's refurbishment of Unit 6 which is expected to commence in 2020. Approximately CAD 10 billion of these projects are expected to enter service by early 2019. Those include the NGTL System expansions. Columbia's mountaineer, WB and Gulf XPress projects, the Sur de Texas natural gas pipeline in Mexico and the Napanee gas-fired power plant in Ontario. We also continue to advance over CAD 20 billion of projects under development, including Keystone XL and the refurbishment of another five reactors at Bruce as part of their long-term life extension program. And finally, we have made progress on funding our capital program by raising approximately CAD 9.1 billion this year. That includes CAD 6.1 billion of long-term…

Thanks, Russ, and good morning, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares was CAD 928 million or CAD 1.02 per share in the third quarter of 2018, compared to CAD 612 million or CAD 0.70 per share for the same period in 2017. Excluding specific items, comparable earnings of CAD 902 million were at CAD 1 per share in third quarter 2018, or CAD 288 million or CAD 0.30 per share higher year-over-year. This equates to a 43% increase on a per share basis, after giving effect to the dilutive impact of common shares issued under our dividend reinvestment plan and aftermarket program. These, along with other funding activities, do however have us well on track to return to long-term targeted leverage metrics following the 2016 Columbia acquisition and continuing record capital program. Our positive results reflect operational strength and solid cash generation across all our businesses, particularly U.S. Natural Gas Pipelines and Liquids Pipelines, and include the net benefits of the U.S. Tax Reform. Turning to our business segment results on slide 15. In the third quarter, comparable EBITDA from our five operating businesses was approximately CAD 2.1 billion, a CAD 389 million or 23% increase from 2017. Canadian natural gas pipelines' comparable EBITDA of CAD 522 million was CAD 22 million lower than for the same period last year. I would note that for Canadian natural gas pipelines, changes in depreciation, financial charges and income taxes impact comparable EBITDA, but do not have significant impact on net income, as they are almost entirely recovered in revenues on a flow-through basis. Net income for the NGTL System increased CAD 9 million compared to third quarter 2017, as a result of a higher average investment base from continued system expansions, partially…

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. If you have any further questions, please re-enter the queue. And with that, I'll turn it back to the conference coordinator.

Thank you. We will now take questions from the telephone lines. We have a question from Linda Ezergailis from TD Securities. Please go ahead. Your line is now open.

Thank you. Appreciate the update on Keystone XL. There's a lot of moving parts in the various work streams. I am wondering if you could help us though distill it down to a sense of when the earliest you might get to an FID, based on your expectation of when certain regulatory and legal processes can conclude? And also give us a sense of are there any sort of construction windows that you need to put next year that you might miss if you don't get to FID by a certain point?

Linda, it's Paul Miller here. On the first question about the regulatory hurdles and the timing of those hurdles, there's three in place now. The first one is the challenge to the Presidential Permit in the Montana Court. The judge has indicated that he will rule on the items by December 1. So we would anticipate a decision here over the next two months. The other challenge is the challenge to the approved route in Nebraska by the Public Service Commission that is being challenged at the Nebraska Supreme Court. The written submissions are in, they were in last May. The oral argument is being held to-date. At that point, it's in the court's hands and we would anticipate a decision from them in late December or early 2019. The third area of permitting is the permits from the Bureau of Land Management which governs the access to the federal lands and permits from the Army Corps of Engineers. The issuing agencies have indicated that, with the expected issuance of the supplemental environmental impact statement here in early December, that they would issue those permits in early January. So, with that, we continue our construction planning and preparation in anticipation of resolution of these legal and regulatory hurdles to prepare us for a start of construction in 2019. But we'll have to reflect on the rulings that do come down from the courts as well as the federal agencies. As far as construction activity, we have planned for a two-year construction. That two-year construction takes into consideration the various windows of construction we have and areas where we don't or are not allowed to construct. The most significant would be in the northern part of the U.S. where there's various windows that are close to us in that January to, let's call it, mid to late Q2 time period. So our planning works around those windows. So, to the extent that we are able to proceed to construction in that time period, we would avoid those windows. And to the extent that our resolution of the legal and regulatory hurdles is not in hand until later in that period, we would start construction in those northern tiers in that June time period.

That's helpful context, Paul. Now, I'm just wondering as a follow-up – maybe this is more a question for Don. I realized we might be hearing this at your upcoming Investor Day, but can you give us a sense in the meantime maybe how you're thinking of your options for financing Keystone XL? You've completed your financing requirements for 2018. So I'm wondering if you might kind of accelerate your funding for 2019 and start thinking about the various levers for Keystone XL, depending on obviously timing of construction expense?

Yeah. Good morning, Linda. Yeah. In terms of 2019, we're in very good shape entering the year. We actually have a sizable debt maturity in early January that I believe we've effectively prefunded with the activities we've undertaken to-date. So we have a good start on 2019 already. In terms of Keystone XL, I'll reiterate the themes that we've discussed previously, basically it will be an all-of-the-above strategy. Keystone XL will bring hybrid capacity with it. As we stated previously, we can issue hybrids up to about 15% of our capital structure. So, as the balance sheet grows of Keystone XL, that would be one lever there. Portfolio management would play more than the token role here. So we do have a sizable portfolio of saleable assets, contracted, that we would be willing to part with to fund part of a Keystone XL program or, alternatively, to avoid share count growth in the future as well. We would entertain JV partners on this project and other considerations would be obviously permutations of equity in the form of DRP, ATM and discrete equity for this. So, basically, everything is on the table here. We'll work towards final costing and see what the timing is. But, again, it's an all-of-the-above strategy.

Thank you. I'll jump back in the queue.

Thanks, Linda.

Thank you. We have a question from Jeremy Tonet from JPMorgan. Please go ahead. Your line is now open.

Good morning.

Morning, Jeremy.

I wanted to continue with equity here and just get a finer point on how you think about that going forward. So, next year look like it's just the DRP, but just wondering under what circumstances might you do the ATM or discrete equity offering again? Is it really just if projects are above the CAD 36 billion secured level? And is that kind of like the determining factor there is whether or not you would issue equity in any of those forms?

Good morning, Jeremy. It's Don. Yeah. We will continue to look at everything on a per share basis. So, if it makes sense for us to sell assets to avoid future share count growth, we'll do that. Depends on the nature and the magnitude of what might come in the door in addition of CAD 36 billion. We are gravitating back here towards our historical live-within-your-means doctrine. We want to eliminate DRP issuance here at some point in 2019 and then we'll see what comes in the door from there. These are all levers we can pull. But, again, I'll just reiterate it, everything is on a per share basis here. So, in the absence of a major new initiative such as a Keystone XL, we think we're in pretty good shape here, and that's kind of our philosophy going forward.

That's helpful. Thanks. And when it comes to portfolio management, just wondering if you could update us there as far as how you see the strength of that market. Has that changed at all or is it still kind of a strong market? We've seen some good multiples posted recently. And with Coastal GasLink, is there kind of a targeted ownership level that you would be comfortable with? Could you go below 50% or how would you think about that if you bring partners in there?

Yeah. The bid is strong for contracted assets and we're seeing that across our portfolio as we look at monetization candidates here. Thumb in the air, we could see like CAD 0.5 billion of contracted EBITDA as being candidates for sale. So you put a reasonable multiple on that and that could be a substantial source of funding for us going forward. And again, the amount of money looking for contracted infrastructure assets is substantial. That gravitates into Coastal GasLink. So we have seen substantial inbound interest in participating in that on a joint venture basis. In terms of where we would ultimately end up in terms of equity ownership, I'd give you a range of us retaining somewhere between 25% and 49% ownership post bringing in JV partners.

That's all very helpful. Thank you for taking my question.

Thanks, Jeremy.

Thank you. The next question is from Ben Pham from BMO. Please go ahead. Your line is now open.

Okay. Thanks. Good morning. To continue on Coastal GasLink, and with the (42:50) filing and the NEB looking at it in terms of jurisdiction, are you still moving forward the status quo of preparation, CapEx spending, looking to sell down the JV regardless of what's going on behind the scenes with the NEB, or are you taking more of a wait-and-see just given that there is a difference between the pipe in service and the LNG in service?

Hey, Ben, this is Karl. Let me just start by saying TransCanada is disappointed with the NEB decision to move forward to review jurisdictional matters here. We do know they have a job to do and we will be cooperating with the job and participating in that hearing. But I will say that we have valid permits from an appropriate regulatory agency right now and we do intend to continue our construction process for this project as we speak. If something happens in the future where a jurisdiction does change before we finish construction, then we would expect a seamless transition of the premise, just like we have experienced in other jurisdictional changes through the last history of TransCanada. So, from our perspective, we will cooperate and work with this hearing that they're going to have on the jurisdictional matters, but we will also be starting our construction with the permits that we have.

Okay.

Ben, it's Don here. In terms of the project financing and JV angle here, we've been working on the project financing for quite some time and the JV side is ramping up as we speak here. Given the spend profile of CGL where the bulk of the spend is in 2020 and 2021, there is no pressing need to get all this placed in the coming quarters here. That said, we continue to move towards that. At this point, we don't see it as materially impacting our funding plans and JV plans.

Okay. And then second question, following on some of the questions about the funding, and it seems like you're quite sensitive to the equity side of the balance sheet, just where stock's moving and seizing the ATM, and maybe less reliance on the DRP, maybe sell more assets. So I wanted to clarify as part of that, is there a little bit of a tweak in the dividend language in the slide? I know 8% to 10% is still quite strong, industry-leading, you guys can certainly grow out those levels. But is there a little bit of a different positioning on that versus Q2?

Yeah, it's Don here. Yeah. The nuances, the words upper end aren't there. It shouldn't be construed as we may be at the upper end. And this should not be seen as any downgrade of our expectations in the future. Our commitment to 8% to 10% is certainly reaffirmed through 2021. It is affordable (46:04) within our long-established payout metrics. On balance, it provides us some latitude as we look at credit metrics, growth profiles. And philosophically, on the margin, if it makes sense to not grow the dividend quite as quickly, and we're talking marginal dollars here, but philosophically to avoid share count growth that's something in the low-50s, high-40s here, that's really where we're coming from on this.

Okay. Thanks for that. Would generally agree with that. Thanks a lot, everybody.

Thanks, Ben.

Thank you. We have a question from Robert Catellier with CIBC Capital Markets. Please go ahead. Your line is now open.

Hey. Good morning, everybody. I just want to understand what level you might sell Keystone XL down to, understanding that there's lot of other levers that would result in that decision. But what level of asset sales, for example, would you have to attain in order to retain 100% of Keystone XL?

Hi, Robert. It's Don here. We really haven't landed a number at this point. This is a very attractive project. But what we're trying to convey here is we'll look at everything on a per share basis. So we haven't landed any specific range on what we would sell down to. It may be nothing and we'll balance that against the equity requirement there. So, as we finalize costs and what else is on our plate, that will inform our decision on that front. As well, we will go to all of the rating agencies, as we did prior to Coastal GasLink, and then engage the rating advisory services on various financing scenarios and see what the outcome is there. So, quite a ways to go before we land on anything on that front.

Robert, I think as we've always approached these things, as Don mentioned, we've got several opportunities to monetize various assets in our portfolio. They're very attractive to market, as is an interest in Keystone XL, and will be driven by long-term shareholder value. So the components of the analysis include what is the implied cost of capital and as always, we seek to find the lowest cost of capital amongst the various levers we have in front of us. And until we get through the analysis and have conversations with people, we can't make that call. But I think the message that we're sending today is that we have several levers to rely upon. As you know, our most expensive cost of capital, especially at the current time, is equity and we're very sensitive to that. So we're looking at other levers in our portfolio. And we're very comfortable with the flexibility that we have there and are comfortable in our ability to finance our programs, including Keystone XL going forward.

Okay. Thanks for that answer. And then just I'm a little curious as to why the regulated maintenance capital expenditure for Canadian Mainline has changed. It looks like it's down to CAD 1.9 billion from CAD 2.5 billion. What's behind that?

Yeah. Robert, it's Karl. Maybe I can just say this that we're always refining our estimates of maintenance, especially maintenance capital, depending on what our view is of equipment performance usage need on our system. So, changing our maintenance capital is not all that unusual. I will say that we have been at elevated levels the last few years as we've been increasing the volumes on our system. As our system gets more full, we need to put more maintenance in. I would suggest kind of on a long-term basis for the Canadian – most of this decrease that you referred to came out of the Canadian gas pipeline systems. Again, I would suggest on a long-term, we'd be looking at maybe CAD 600 million a year of maintenance capital coming out of Canadian systems. So, that's down over the forecast period that then what you've seen the last couple years. But I think actually CAD 600 million is a good run rate. And as our system becomes more heavily utilized, you'll see it go up a little bit temporarily, but it should always adjust back to the CAD 600 million range.

Fantastic. Thank you.

Thank you. The next question is from Tom Abrams from Morgan Stanley. Please go ahead. Your line is now open. Tom Abrams - Morgan Stanley & Co. LLC: Thank you. Couple of quick ones, and then, a little bit longer one. But the two quick ones are, your balance sheet ratio that you expect at the end of the year, let's start with that.

It's Don here. In terms of debt to EBITDA? Tom Abrams - Morgan Stanley & Co. LLC: EBITDA, yes.

Yeah. We'll be within the range as expected by the rating agencies as we continue to de-lever post CPG and get those assets in service. How I'd describe it is the run rate as we bring to CAD 10 billion of assets, as Russ outlined, into service here over the coming months and with our expected cash flow from them, we should be on side with that 5 times debt to EBITDA, 15% FFO to debt, on a run rate basis as we exit this year and into early 2019. Tom Abrams - Morgan Stanley & Co. LLC: Okay. The other quick one is when you say the finalized costs for Bruce Power, I think you said CAD 2.2 billion, that's finalized with the regulators or is that something you've done with the contractors?

Well, yeah. So, that cost that we've put out there for Unit 6 is the full cost of both the Major Component Replacement and the Asset Management through to 2023. And that is a cost that we have actually with its accumulation of cost from the contracts we've put up for all the various subcontractors and equipment suppliers. So, when we put that CAD 2.2 billion out there, that's our 50% share of the full cost of the Unit 6 replacement, both the Major Component Replacement and the Asset Management. So, that cost I would just point out is under the kind of threshold that we had in the original contract. So there is no real decision on go or no-go. The IESO right now is just making sure our project is complete and they will probably be issuing sometime in November kind of their comments on that. But we're expecting to proceed as per our proposal to them. You will see the adjustment in the rates for Bruce coming in at the beginning of April. As Russ said in his opening notes, we will adjust the price per megawatt hour that we sell to them up from about CAD 68 to the mid-70s. You'll see that starting April 1. And Unit 6 comes off on the beginning of 2020, so in January of 2020. So we will actually be collecting the monies before the Unit 6 comes off. Tom Abrams - Morgan Stanley & Co. LLC: Great. Thanks. And then my last question is just how you're thinking about TCP these days?

Yeah. It's Don here. There's still some regulatory process to go through for the assets in there. So we're still looking to clarify exactly what the long-term cash flows are from that. I would describe TCP as neither a source or a use of capital at this time and just leave it at that. Tom Abrams - Morgan Stanley & Co. LLC: Okay. I appreciate it. Well, see you in a couple weeks.

Okay.

Thanks, Tom.

Thank you. The next question is from Robert Kwan with RBC Capital Markets. Please go ahead. Your line is now open.

Good morning. Maybe if can come back to funding, and looking out to 2019, if you just look at the secured capital program, so no kicks or any large projects that would actually add to the 2019 program. I guess, you're messaging the ATM is going to be off. The DRP is going to be on for some portion of the year. How does portfolio management work into your base plan for 2019? Has the decision, as you look at this kind of share count metric, the decision being to leave the DRP on or is portfolio management some amount in the 2019 numbers as well on top of the DRP?

Yeah. It's Don here again. At this point, with the dividend declaration today, the DRP will be on certainly for the January dividend payment. So, as we look through the balance of the year, DRP could go anywhere from a couple quarters to the full year, depending on the capital program and portfolio management. So you shouldn't take silence as an activity on the portfolio management front. And we do have a number of irons in the fire right now. But it's really give and take as to those processes getting to suitable finish lines and what more we might look at. But there's certainly DRP for some portion of the year. The potential is for it to be there all year, but if we can truncate that with sensible attractive portfolio management, we'll do that.

Okay. And then just if I can refine the 2018 EPS outlook, and I don't know if you want to tie it back to the second quarter guidance, but you're talking about fourth quarter looking like the first nine months. So is that an annualization of the nine-month figure or, again, if you want to tie it back to second half it's going to look like the first half? Just if you can refine the message.

Yeah. It's Don here. It's the quality of what you've seen over the first nine months. There's a little bit of seasonality in our business, particularly on the U.S. gas pipeline side. But I would see that the strength you've seen three, nine months here continuing into the fourth quarter and through 2019 as well here. So, as you know, we don't give specific point EPS guidance, but is it four-thirds of what you've seen year-to-date, I won't get that granular, but factoring the seasonality and continuing the strength you've seen.

Put differently though, is there nothing wrong at least as a baseline from the statements you made for Q2, second half looks like first half?

Yes.

Okay. That's great. Thank you.

Thanks, Robert.

Thank you. The next question is from Rob Hope from within Scotiabank. Please go ahead. Your line is now open.

Good morning, everyone. I want to circle back on the commentary regarding joint ventures for both Coastal and Keystone. Arguably, you've created value through the development process of these assets. Just wondering how you would look to capture that through a JV arrangement? Could you get an upfront payment, would it be more of a promoter, how are you thinking about JVs there?

Robert, I think as I mentioned earlier and you've just highlighted, these projects are well constructed and highly contracted and therefore very attractive in the private markets currently. And we're just going through that process right now to determine what is that value that can be created and what's the best way to surface it for our shareholders. So, I'd say at the current time, we haven't concluded. But I would say that a promote either upfront or over a period of time wouldn't be unexpected, that we think that there's considerable value in here for our shareholders and we would love to surface that. To maximize value first is not to give up value. So, how we go about doing that in negotiation will be with that focus. And then, secondly, mindful of our current financing requirements. And to the extent that upfront payments or things like that can be used to offset equity issuance, obviously that would be a consideration in our valuation of various potential partners. So, as Don I think alluded to, A, we're very comfortable with the array of options that we have in front of us and that we'll look to optimize those options to best fit both long-term shareholder value and to minimize share count growth.

Yeah. It's Don here. We're always cognizant of balancing complexity, structural subordination and control of these assets as well. So there are some other qualitative factors we bear in mind here.

All right. Appreciate that. And then just I guess moving over to the NGTL System, the expansion that you've announced last night, more broadly how are you thinking about the supply-demand balance out of Western Canada, now that you have LNG moving forward? Could we see less of an emphasis on longer-term contracts eastwards out of the basin and more focus on the westwards?

Hey, Robert. This is Karl. So I guess my feeling on that is that there's enough of resource spaces, not producibility in that resource space that we could have. It's not an either or/or anymore, it's both. So, even though there's obviously going to be in the next four, five years a very robust Western market for the natural gas going through Costal GasLink, we're still working as hard as we can to move gas molecules in the Eastern Canada into the Midwest, down into our U.S. pipelines for further transport into the Gulf Coast, if that works some. So I don't think – I think given the nature of the resource there and just the sheer amount of gas and producibility of it, I think it behooves us to continue looking for markets for our producer customers. So, that's what we're going to continue doing.

Yeah. And I'll just augment Karl's comments. There's over 1,000 Tcf recoverable reserve in the Western Sedimentary Basin. I think it's proving itself to be one of the lowest cost, most prolific basins in North America, if not the world, currently producing in the 17 billion cubic feet a day kind of range. If you kind of look at a similar basin in the Appalachian that went from 0 to 40 Bcf (1:00:57) in a very short period of time because it had access to market as an example of where we think the basin can go long-term, we believe it's only constrained by market access. And therefore, as Karl said, that's what we're working on both to the West Coast and south to California, into the Midwest and even into the Northeast U.S. And as we've seen in recent open seasons, the Northeast U.S. utilities and even far eastern Canadian utilities are interested in Western Sedimentary Basin. So, as we look forward, I think as I mentioned in my opening remarks, Coastal GasLink has the ability to expand to 5 Bcf a day. And we fully expect that over time that that's an economic proposition for Shell and its partners that that's a probability going forward, the open seasons that we had downstream. As well, I think as we noted in our release, growing intra-basin markets, the growth and power generation as we convert from coal-fired generation to gas-fired generation, increase gas-fired generation, the industrial development that's coming with petrochemical development as we look to value-add products here in the Province of Alberta, all of those things are new markets which will bolster growth. So we actually don't view that the basin is being limited in that 20 Bcf a day range. If we can create market access, there's no reason why the basin can't grow considerably more than that. So, as Karl said, primary focus for our Canadian gas business right now is around developing markets for our customers and to allow them to continue to increase production.

And just to give you a fill-in for this latest expansion, two-thirds of that expansion kind of physical volume-wise is for new intra-basin market and one-third will be receipt. Of the costs of the expansion, probably 80% to 90% of it will be to go look up that intra-basin market and about 10% to 20% of it will be for the receipt. So, most of this expansion that we brought forward actually is market expansion for production.

All right. Thank you.

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead. Andrew Kuske - Credit Suisse Securities (Canada), Inc: Thank you. Good morning. I think the question is probably for Paul and it just relates to the liquids unit and the marketing numbers that you posted this quarter, which were impressive. But if you could just maybe give us a little bit of color and context around what happened in the quarter and then expectations on a go-forward basis?

Certainly, Andrew. We did see strong results from our marketing entity in the third quarter. Our marketing entity has capacity on various pipes. And with that capacity, they hedge their position. And the vehicle they hedge their position largely is around the Brent-TI spread. And what we saw in the third quarter, and let's call it the third quarter business cycle which precedes, if you wish, calendar quarters, we saw a significant increase in those differentials kind of in that May timeframe and were able to pick up some of that value before the decline. And then, after the decline, the market came back. So I would expect to see our marketing results in Q4 to be similar and maybe even an increase to what we saw in Q3. When we look forward to the forward curves on the various differentials, I would anticipate similar results for our marketing entity into calendar 2019. Andrew Kuske - Credit Suisse Securities (Canada), Inc: Okay. That's very helpful. And then maybe just a follow-up. Just operationally, on Keystone, what are you running volumes at and have you managed to eke out any extra capacity either by way of scheduling, batching, DRA?

Certainly. So I'll answer it from two perspectives. The ex-Alberta Keystone System has capacity of 590,000 barrels per day and that's our authorized capacity. And of that capacity, we've contracted 555,000 barrels per day and that's about 94%, and we are required to set aside 6% for spot. And with the direct differentials we're seeing out of Alberta, there is a high demand for that spot. So we are effectively running full on the Keystone System. On the southern leg, our Marketlink system which runs south of Cushing, that's a pipe that has run probably in that 300,000 to 4000,00 barrel per day range historically. But over the course of the last year, we have looked to increase the capacity on the capability of that line. We've increased that capability to probably the mid-600,000 barrel per day range. And with, again, the differentials we're seeing between Brent and TI, we're flowing in that range in that low- to mid-600,000 barrel per day range. Of that capacity, our strategy has always been and will continue to be pursue sustainability and pursue quality. So we take the opportunities, as the capacity increases and as the market demand increases, to term out some of these volumes. So, on the Marketlink system of that capacity, we're probably running about 80% contracted. So, again, I see a sustainability for the Keystone System as well through Q4 and into our calendar 2019. Andrew Kuske - Credit Suisse Securities (Canada), Inc: That's great. Thank you very much.

You're welcome.

Thanks, Andrew.

Thank you. The next question is from Praneeth Satish, Wells Fargo. Please go ahead.

Hi. Good morning. Just wondering if you can provide just a general update on Mexico, I guess just what you're seeing there and how gas demand is tracking relative to your expectations.

Oh, hi. It's Karl. So, maybe I can just kind of update a little bit on our construction program. The Sur de Texas, which is the large offshore pipeline that we're working on, we're in pretty good shape on that actually. We've had some rough seas the last few weeks, so we've had our boats in dock but it's really, we have one more area of tie-in, land to sea tie-in to do and then we'll start calling for gas. So we're still predicting end of the year in service. With the rough weather we've had, maybe it's slipped but then I'm talking days and maybe a few weeks, not anything longer than that. So, right now, the seas are calm and we'll be moving our pipeline offshore to get it interconnected. So, that will happen over the next couple weeks, hopefully, barring any unusual weather patterns. Our Villa de Reyes has come along fine. As you know, the Villa de Reyes is the pipeline that is running through all the artifacts. And I think we ran into a mighty archaeological finds as we were doing that pipeline. That doesn't stop the pipeline indefinitely, but it does slow it down as we have to wait for the Government of Mexico to investigate all these archaeological finds. So it has been delayed. I will point out that because of the force majeures that we've had on all pipelines, two of them (1:08:28) Sur de Texas and Villa de Reyes, we are collecting actually our revenue on them right now. We have contracts that say if the delays are not – if they're not from TransCanada's doing, that we can collect our revenues on them. So we are collecting the revenues on them, even though they haven't gone into service. We expect Villa de Reyes to be in service in 2019. As we clear up all the archaeological sites and we move on, we will bring that in next year. Tula is a pipeline that we have actually demobilized on. We have actually pretty much finished everything we can construct on there. But we have one 90-kilometer section of Aboriginal issues, which is a Government of Mexico obligation to sort out. We're still hopeful they'll get that sorted out sometime in 2019 and we can finish. We are hoping that we can put it partially in service before then. And again, we are collecting all of our revenue on that pipeline because that is a force majeure that fits the definition of – that allows us to collect our revenue. So I think our projects are going fine in Mexico. We are looking forward to next year completing them, save for Tula, completing them all and putting them all on physical (1:09:44) service. We did put Topolobampo in service this year after a similar Indigenous issue. It is flowing gas right now. So we're looking forward to next year to get the system operationalized and flowing gas.

Okay. Thanks for that. And then, just turning to the balance sheet quickly, if you pursue project financing for Coastal GasLink, will the rating agencies treat that debt as completely off balance sheet or will they consider your proportionate ownership of that debt?

It's Don here. To be determined. And again, as I mentioned for KXL and what we did with Columbia, we will engage the agencies' rating advisory services as we look through that. Depends how it's structured, obviously, commercially and what covenants and conditions are on that, but we would be hopeful to achieve proportionate consolidation of that debt.

Thank you.

Thank you. The next question is from Patrick Kenny from National Bank. Please go ahead.

Yeah. Good morning, guys. I wanted to get your thoughts on East Coast LNG. Pieridae looks to be closing in on FID, what this could mean for new long-term contracts down the Mainline over the near-term as well as what the expansion opportunities might look like for TQM and PNGTS.

Hi. It's Karl again. We've been in discussion with several developers on the East Coast of Canada. I will say that the developers there, both Pieridae and others, they have been – they seem to be well-financed, they seem to be progressing. They seem to be progressing in their project development. To-date, we do not have any transportation agreements with any of them. So we are still discussing with all of them kind of what services that we can offer. Obviously, if an East Coast LNG does go ahead, we are interested in expanding on our system to accommodate that. Right now, most proponents are looking to use our system up to Portlands and then going through Portlands and then maybe utilizing the Maritimes and Northeast infrastructure until that is full. So, that's kind of the path most are looking at. Although that path can't accommodate a lot of gas, it can probably accommodate – it can probably work with one of the projects. But as I said, to-date we don't have any transportation agreements with any of them. So we'll continue working with them. And as their projects progress and get more mature, we'll be dealing with their request for transportation services at that time.

That sounds good. And then maybe just a quick follow-up on your comments on the NGTL expansion announced yesterday. From an Alberta demand pull perspective, just based on your internal forecasts, do the expansions announced yesterday fully cover what's needed for coal to gas power conversions, petrochemical growth, oil sands growth into next decade? Or could we expect the Phase 2 expansion on NGTL related to these Alberta customers at some point in service beyond 2022?

That's a good question. That's something that obviously we ask ourselves all the time. So let me say this, for the intra-basin demand, I think these are the requirements that were in our queue (1:13:26) at this time. These should – I think a portion of it obviously is for coal to gas and a portion is for chemical. These are what proponents have come and asked us right now to want to sign up for. We do have ongoing discussions with other potential increases in intra-basin market that we're working outside of this. And that may or may not come to fruition in the future. So, I find it hard to say that this will take care of us for a long period of time, because this is a growing intra-basin market. But this is all we have right now. These are the people that we're willing to set up and sign contracts for us.

All right. That's great. Thanks, Karl.

Thanks, Pat.

Thank you. The next question is from Alex Kania from Wolfe Research. Please go ahead.

Great. Thanks very much. This is just a follow-up on Mexico. We've just seen a little bit of volatility in the markets down there over the past week or so, just with respect to I guess the airport decision by Obrador. Is there anything that we should read through to that on the existing projects? I know that you don't have a lot of kind of incremental capital to be put to play there, but just kind of considering what your thoughts are on that.

Yeah. Sure. It's Karl. And I'm aware of the issue that you're talking about. But I guess I can say this, we haven't had a lot of exposure to this new administration. They will be kind of in place here late this year or in the new year. And we do expect to become more involved with them and to get into all the ministry offices and whatnot and have more thorough conversations with them. And I might be able to answer this a little bit more directly at that time. But from where I sit right now, their natural gas strategy and just natural gas into Mexico is very important for the future growth of the Mexico economy. It's important for their power plants. It was a great strategy to replace oil with gas and sell the oil internationally. There's a great strategy for them to get industrials using cheaper natural gas rather than fuel oil in their processes. So it is a very important element of the future growth of their economy. And I would expect our infrastructure plays a very critical part of that important role. And so, my expectation is that the government will work with us to make sure that this infrastructure plays an important part in this economy and my expectation is that, once they're in place, we will be working well with the government to make sure that these gas pipelines are fully utilized and the benefits to Mexico are realized through the work we do. So, yeah, from right now, it's so important for the Mexico economy, I just can't envision anything other than us working together to make sure that we get the full use – both Mexico and TransCanada gets the full use of these assets.

Great. Thanks so much.

Okay. Thanks, Alex.

Thank you. The next question is from Shneur Gershuni from UBS. Please go ahead.

Hello. This is actually Aga for Shneur. So, my first question is, do you see a need to twin or expand Marketlink to handle incremental volumes from Keystone XL? Could you please talk about the market dynamics there? Thank you.

Certainly. Hi, it's Paul here. Where we're focused right now is advancing of various projects, including Keystone XL. But part of our opportunities around will be legacy systems and Keystone XL kind of revolves around that footprint we have. We have a very good footprint which starts in Northern Alberta and moves straight down the Mid-Continent to the U.S. Gulf Coast. So we're always looking for opportunities to secure additional and growing supplies and deliver them to market. And at this point, market dynamics on the Gulf Coast look quite attractive. As I indicated earlier, there are some high differentials. We do see two or three different type of proposals in play now and under construction. So we'll see how that market dynamic plays out here over the over the next year to determine what our go-forward is going to be. Our approach to business development is to always secure long-term contracts for our infrastructure. On Keystone XL, which we'll use a portion of the Marketlink capacity we have, these 20-year contracts, to the extent that the marketplace requires an additional pipe flowing from Cushing down to the Gulf Coast, and we can secure long-term contracts for that infrastructure, that's certainly business we can get.

Perfect. That's very helpful. I have also one more question on funding. So, do you have some call around funding plans, should Keystone XL be FID-ed? And then when you think about your long-term target, what's your willingness to consider leverage ratio below 5 times and, say, 4.75 times? Thank you.

Yeah. It's Don here. I did address that earlier in terms of how we would approach Keystone XL funding. So I'd refer you to that answer. In terms of the credit metrics, as I mentioned, we will engage the rating advisory services, other credit rating agencies with various funding scenarios, to see what the impact would be. At the end of the day, we want to return to high-4s debt to EBITDA ratios as a run rate and minimum 15% FFO to debt. How that works through the construction period is pursuant to discussions between us and the rating agencies.

Thank you so much. That's it from my end.

Thank you. Thanks.

Thank you. We have a question from Harry Mateer from Barclays. Please go ahead.

Hey, guys. Good morning. Just a follow-up to the last question. Not to split hairs but Moody's has viewed sort of 5.0 times and above as a potential downgrade trigger. So it sounds like maybe a bit of a shift to high-4s, although you're still consistent with 15% FFO to debt. Can you just talk about how you think the value of that A3 rating at Moody's? Is it important or less important given S&P took you guys down earlier this year and you still have access to low-cost debt capital?

Yeah. Yeah. The A rating is important to us, but we'll take a balanced approached to it. If there is a significant moving of the goalpost there's – we need to factor in both equity and debt holders as to how we look at that. The high-4s guidance that we're giving here is – we're not going to redline this. The intent is to give us some headroom there. And it is a very predictable business model. So we can see these cash flows for a very long period of time. So the intent is to be on side with that and the metrics that have been outlined for us. I wouldn't say the split rating between S&P and Moody's has changed our philosophy on this at all. So we'll just continue to fund this company in the way we've done it for the past 15, 20 years here. And the right-hand side, we put substantial subordinated capital on the books here since the Columbia acquisition. And I would say the left hand side of the balance sheet has never been stronger in terms of the asset base and the longevity of the cash flows there.

Okay. Thank you.

Thanks, Harry.

Thank you. We have a question from Joe Gemino from the Morningstar. Please go ahead.

Thank you. I have a quick question regarding any thoughts that you may have on Enbridge's Mainline. If you could expand a little more on what you think about them pursuing long-term take-or-pay contracts and what impact that may have on the Keystone and Keystone XL?

I wouldn't want to comment on projects in pipelines that we're involved in. What I can tell you, I guess just reiterate both my comments and policies. The demand for our existing system and for Keystone XL has never been greater. Obviously, you can see by the differentials in the marketplace that producers want access to markets and are willing to sign long-term contracts. So the guidance that we've given you with respect to both fully contracting base Keystone and Keystone XL are consistent with that as we believe that will yield. Our current operating results would I guess indicate the demand for our system is great today. And what we're seeing from shippers, both producers and refiners that want to contract on a 20-year basis, that that demand remains strong as well and we'd expect to fully contract. I can't really comment on anybody else's projects though.

Right. I appreciate that. Thank you.

Okay. Thanks, Joe.

Thank you. Ladies and Gentleman, the call has now concluded. If there's any further questions, please contact TransCanada Investor Relations. I would now like to turn back the meeting over to Mr. Moneta. Please go ahead, sir.

Yeah. Thanks very much, and thanks to all of you for participating this morning. We very much appreciate your interest in TransCanada and look forward to speaking with you again soon. Bye for now.

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