Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2017 Fourth 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 afternoon, everyone. I’d like to welcome you to TransCanada’s 2017 fourth 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, Liquids Pipelines; 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. Our comments maybe a little longer this afternoon as we will also touch on our 2018 outlook. A copy of the slide presentation that will accompany their remarks is available on our website. It can be found in the Investors section. Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Mark Cooper or Grady Semmens 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. 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 like to 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. These measures are used to provide you with additional information on TransCanada’s operating performance, liquidity and its ability to generate funds to finance its operations. With that, I’ll now turn the call over to Russ.

Thanks, David, and good afternoon, everybody. And thank you very much for joining us today. It’s hard to believe another year has passed but as outlined earlier today in our fourth quarter news release, 2017 was a very successful year for our company. In addition to delivering record financial results, we did make significant progress on a number of other fronts that will position us for continued growth and success. First of all, we completed the integration of the Columbia Pipeline Group, and we are on track to realize the US$250 million of annual synergies that we targeted at the time of acquisition. We also acquired the Columbia Pipeline Partners for $1.2 billion giving us 100% ownership in Columbia’s core assets and again simplifying our corporate structure. We also completed the sale of our U.S. Northeast Power assets and repaid the Columbia bridge loan facilities. And we continue to advance our $23 billion near-term capital program by placing approximately $5 billion of assets in the service. Also in 2017, we replenished our growth portfolio by adding more than $3 billion of Canadian and U.S. Natural Gas Pipelines expansions to our inventory of commercially secured projects. And earlier today, we announced another $2.4 billion expansion program on the NGTL System. In addition, we also advanced our over $20 billion of medium to longer-term projects, including the Keystone XL pipeline, the Coastal GasLink pipeline and the Bruce Power life extension program. And finally, we successfully funded $9.2 billion capital program by raising substantial moneys across the capital spectrum on very compelling terms. It included more than $6 billion of long-term debt and hybrid securities from Canada and the United States. In addition, we completed a drop-down of TC PipeLines, LP for US$760 million and we realized another $1.1 billion through the recovery…

Thanks, Russ and good afternoon, everyone. As highlighted in our news release issued earlier today, we have reported net income attributable to common shares in the fourth quarter of $861 million or $0.98 per share compared to a net loss of $358 million or $0.43 per common share for the same period in 2016. Per share amounts reflect the dilutive effect of having issued 161 million common shares in 2016 plus additional shares through the dividend reinvestment and aftermarket programs in 2017. Fourth quarter results included an $804 million recovery of deferred income taxes as a result of U.S. Tax Reform, a $136 million after-tax gain related to the sale of our Ontario solar portfolio and a $64 million after-tax net gain related to the monetization of our U.S. Northeast power business. These positives were partially offset by a $954 million after-tax impairment charge for Energy East and related projects as a result of our decision not to proceed with the project applications and a $9 million after-tax charge related to the maintenance and liquidation of Keystone XL assets, which costs were expensed in the quarter pending further advancement of the project. Fourth quarter 2016 included a $870 million after-tax loss related to the monetization of our U.S. Northeast Power business, a $68 million after-tax to settle the termination of our Alberta PPAs, an after-tax charge of $67 million for costs associated with the acquisition of Columbia and $18 million after-tax charge related Keystone XL assets and a $6 million after-tax charge for restructuring costs. All of these specific items, as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Fourth quarter comparable earnings were $719 million or $0.82 per share compared to $626 million or $0.75 per share in 2016. For…

Thanks, Don. And to those of you listening, we very much appreciate your patience as we got through that, obviously, a lot to cover, including hopefully giving you some color on our 2018 outlook. With that, 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 any additional questions, please reenter the queue.

Thank you. We will now take questions from the telephone lines. [Operator Instructions] The first question is from Jeremy Tonet from JPMorgan. Please go ahead.

Good afternoon.

Hi, Jeremy.

Just want to start off with the crude oil pipeline segment, quite a strong result this quarter there. And was just wondering if you could help us a little bit more, what’s kind of like more of a ratable number for earnings this – EBITDA this quarter, there was some kind of upside with liquid marketing and other thing. So just for modeling thinking forward, what kind of a repeat or a number that repeat and also just on the line pressure be fully back on Keystone and what type of a near-term impact should we expect from that?

Sure, Jeremy. It’s Paul Miller here. I’ll start with the pressure of de-rate. We continue to work with the regulator on the event. We continue to look at the root cause of the leak we had. And ultimately, it will be the regulators call when the pressure de-rates is lifted. So we continue to work with them. The pressure de-rates had a modest effect on our flows, nothing that impacted our Keystone financial results materially. As far as a ratable going forward, the leak did not impact the southern part of our systems, south of Cushing. And that’s where we saw high differentials in the fourth quarter, which made transportation on our Marketlink system quite attractive. So we were able to attract on contracted volumes. Our marketing entity also participates in that marketplace and it to realize on some good volumes in the fourth quarter. We have seen the differentials come off, since then they started off strong at the beginning of the quarter but they have trailed off.

Okay, thanks. And then just want to go to Keystone XL real quick here. And was just wondering if you could help me think through, what the next steps we should be looking for here? What are kind of the hurdles to an FID and also just as far as the Tax Reform’s concerned is, KXL qualify for immediate expensing there?

I’ll start off with next steps. As we’ve indicated previously, we have commenced our construction planning. And it would be our anticipation to ramp up that activity as the permitting process advances in 2018. We will commit capital to that activity and we want to position ourselves to be able to commence construction in 2019. We do have some items that we have to attend to in 2018, including securing additional land in Nebraska with the approved route to Nebraska. It does leave us in a position of requiring additional tracts of land. So we have begun the outreach to our landowners, indigenous groups and other stakeholders, and we look forward to negotiating with them to secure that land. In regard to the Tax Reform, I’ll turn that over to Don.

Yes, Jeremy, it’s Don here. Yes, Keystone XL is a nonpublic utility by the way it looks under the act. It should qualify for immediate expensing. To the extent, we would avail ourselves of that will depend on our broader tax situation in the States and our tax shelter there but yes, it should qualify for that.

That’s helpful. Thank you for taking my questions.

Thanks Jeremy.

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

Good afternoon. If I can just follow-up more broadly on Tax Reform, just wondering if you could talk a little bit more though about the cash flow impact with that expectations on any cross-border tax structures where you are in terms of interest deductibility caps, both for the EBITDA and the EBIT transition?

Sure, Robert. It’s Don here. I’ll start out but I maybe turn it over to Stan here to talk a bit about his specific business here. The U.S. Tax Reform, its pretty involved piece of legislation with a lot of interconnectivity here. So maybe would be useful if I just walk through the four key component parts and how they impact us and then speak more broadly to the collective impact at the end here. So the first one is the reduction in the federal rate from 35% to 21% generally, a positive thing as we apply that to our suite of U.S. businesses but the issue here as you know is isn’t a rate regulated business and that’s if and how much of the this benefit will ultimately be passed to our customers and over what time frame. So let Stan maybe speak to that part, then I’ll circle back on the other three pieces.

This is Stan. A big picture wise, you can think of it as a situation where lesser until FERC mandates otherwise or unless there are specific provisions in a prior rate case settlement, the chew up of the reduced tax rates will occur in the pipelines next to rate case. Having said that, various industry segments have sent letters to the FERC Commissioners urging them to require pipelines to reduce rates immediately. Inga and several others have responded on behalf of the pipelines and noted four key points. One is that FERC should respect the security of rate settlements, especially in instances where there are more moratoriums from rate changes in place or where rates are designed on a black box settlement and there is no individual component of the cost of service identified. Two, that FERC has a long-standing precedent of not cherry picking and look at only one element of the cost of service and have changes that required for one component then perhaps changes in all components should be in play. Three, that legally, there’s a significant hurdle that FERC needs to get over with respect to first making a finding that the pipeline rates are unjust and unreasonable. And fourth, most importantly, perhaps and along the point that Don was making, given the implementation of Order 436 back in 1885, a significant amount of competition exists within the pipeline segment, such that a significant portion of our rates are either discounted and that burying the full tax rate or negotiated and contractually not subject to change. So by way of an example, for 2018, about 54% of our revenues fall as either discounted or negotiated rate contracts. In 2019, that will increase to 63% due to the – our projects Mountaineer and Gulf XPress coming online.…

That’s a great color. If I could finish then on Mainline, just with the successful NGTL open season, especially the expansion into the East Gate. Can you just talk about the next steps on bringing back some of the mothballed capacity on the Mainline? And if there are any numbers with respect to the capital that might be required here, that would be great.

Yes, Robert, it’s Karl. So we have closed the open season at the end of the month. And as you’ve seen, we’ve got about 1 Bcf a day of new delivery capacity to the East Gate. So that new delivery capacity that we have sold is scheduled to come on about 2020-2021 timeframe, so we do have a little bit of time. We have two options to provide people mainline capacity from that. One is from existing capacity sitting on the Mainline that is active right now. We do that – we are in large volumes on the Mainline right now, but we are anticipating some non-renewals on the Mainline, so we are expecting a piece of that to come from the existing capacity that we have right now. The rest of it will come from us reactivating capacity that right now, so to speak dormant capacities there, but it isn’t ready to be used. That’s relatively cheap capacity to bring back. It generally just requires some maintenance, it requires some compressor work, some maintenance, some integrity work. So that is relatively – I don’t have the number right now because I don’t know the exact amount that we can bring back, but it is relatively cheap as I said it’s maintenance. They can come back relatively quickly, and we have probably in total about 0.5 billion cubic feet a day maybe slightly more of that capacity available in the Mainline. So we should be able to take care of between that and the existing non-renewals we’re expecting over the next couple of years, we should be able to take care of all the 1 billion cubic feet a day of new delivery capacity quite easily.

Thanks very much.

Thanks, Robert.

Okay, thank you. The next question is from Linda Ezergailis from TD Securities. Please go ahead.

Thanks. Maybe I’ll stay in Canada and ask about some of your regulatory filings with the 2018 NGTL revenue requirement and then your Mainline interim toll filing for 2018 to 2020. Can you comment on the timing of when you expect those processes to be finalized? And how – what are the bookends of possibilities in terms of your economics going forward?

Hi, Linda, it’s Karl. I will start with the NGTL right now. What we have filed in NGTL really is for interim tolls. They were reduced toll on our system but they’re really intended to take – to be in place where we sort of there’s going to be a settlement and/or if there’s going to be litigation. What I can say right now is we’re still working with our shipper group for a settlement. We are optimistic that the settlement discussion is progressing, and we have no plans right at this moment to move to a filing with the regulators. So I think we’re going to work with our shippers for a little bit longer here to see if we can get a settlement. So it will be, obviously, we’re looking for both sides have got needs, our producer group actually needs us to put more capital in the group, we need to be properly compensated and proper tariffs in place for that. So I would expect coming out of there settlement that that does not back us up in anyway, shape or form from the existing kind of financial metrics we have on NGTL. On the Mainline, we have filed the interim adjustments that we had in our six-year settlement. So if you recall six-year settlement had a reopen in 2018 to reestablish billing determinants. So this is kind of what I would call a limited hearing. We have really just meant to reestablish the new billing determinants to take us to the end of 2020 in which case will have the larger hearing from the split between the Western system and the Eastern Triangle of the Mainline. We have filed the application and filed what we believe they’re willing to determine us a new toll should be. Again, the tolls are increased from what we had before. We have had – the board has a lot of comment – comments on that filing, and we’re waiting for the board to get back to us on the process and procedure and that they haven’t done yet. We’re expecting that any time now and we would expect to begin that process here in the second quarter around and maybe even in ends of third quarter but should be relatively soon.

Okay, thanks. And maybe just also very quickly on the North Montney process, and booking, and outcomes and timing?

Yes. Well, the North Montney will be – the final argument from us is due next week, next Tuesday, I believe. And then the board has to come back to us within 12 weeks. So by the end of the second quarter I think we’ll have a decision. If you recall, we are asked on that particularly hearing was that they just lift the – we already have an approval and they’ve just lifted the condition, which was the PETRONAS, Pacific NorthWest LNG preceding. We now have several 10 different customers with 20-year contracts on the system, and we want to proceed with the LNG project proceedings. So that was our request. Unfortunately, the hearing didn’t get expand a little bit into the toll design issues and we will be wrapping up with our final argument, and we will await their decision as to if they will work, if they will see through to our request, which is just on one condition or if we have to do some work on building conditions afterwards.

Great. Thank you.

Thanks, Linda.

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

Thanks, good afternoon. I wanted to ask about the cost of gasoline project and can you remind us the permits there you’ve received and if it’s up-to-date and can you go back at some point of your balance sheet starts to get some momentum there?

Well, hi, Ben, it’s Karl, again. Yes, the permits are well in hand for that. All major permits there’s always some minor local permits that you’ll need as you go into construction, so all major permits are in hand and close to GasLink. Yes, on some of the permits there will be an expiry date, but we have either dealt within expiries come our way or we’re comfortable that we’ll build. I don’t have on my hand exactly what those but it’s just not unusual for some permits that have, some sort of expiries but we’re in pretty good shape the permits that we do have are valid and ready to be used. The – as I said – as we said before, the sponsors of our program that will be Shell and partners on LNG Canada, has said, that they will take it FID one way or the other by the end of this year, so we’re looking forward to have conversations with them.

And can I also ask the South LNG’s stories, no once has been talk about it for a long time and now it’s coming back. Is there some much gas and supply in Alberta that could fit both the Coast LNG side of things and also you can move that gas southeast as well or is it just going to be sort of – unintended consequence of LNG export happens.

Yes. That’s a good question. Let me say this, the reserve potential and the WCSB has gone from – well, I think the last 50 years, we’ve thought it – maybe a 100 Tcf, maybe 125 Tcf, so over 1,000 Tcf right now. And quite frankly I think it’s even larger than that, people have just stopped really counting and so prolific with the new technology. So I and the firm belief that you can do both the expansion of the markets that we’re working on, both south and east and the expansion markets to the West Coast of the LNG. And as a matter of fact I think the producing community agrees with me, the producing community is very anxious to see LNG off the West Coast and they’re very anxious to participate in new markets where we can find markets with even going south GTN or east up to the Mainline. So I’m confident that the production – the reserves are there and the producing communities will enable to produce gas to fit both of those markets or all the included markets.

And then I would just add to – it’s Karl. I would agree with him. I believe that the Western Sedimentary Basin for all intents and purposes only constrained by market access. I think our best example would be the Marcellus/Utica we saw that go from zero to 25 billion cubic feet a day in about a five year period. I mean, it’s astonishing what new technology will do on top of the 1,000 Tcf of recoverable reserve. So as we thought about the Western Sedimentary Basin sort of conventionally here for the last few years going to 17 billion cubic feet a day to 19 billion, I think that’s only constrained by market. I think evidence as you saw here over the last year or two. We’ve eked out 2 billion cubic feet a day of delivery capacity on our system and it chock about forward contracts that range 20 to 30 years. If we were able to create an outlet for 2 billion, 3 billion, 4 billion, 5 billion, 8 billion cube feet a day there’s probably a handful of producers that could supply 25% or 30% of that on their own. So we believe, we’re very bullish that gas is abundant. It’s cheap, and it has a long life and our job is to figure out how we can create market access for it. So I don’t see any unintended consequence. I think it’s a positive. The basin can fit all markets for – I hate using terms like this, but beyond 100 years, if you think the Karl’s terms moved from 100 Tcf to 1,000, both the Appalachian Basin and Western Canada along could supply North American’s 100 billion cubic feet a day need for the next 100 years by themselves. So lots of gas and I guess the story from my view is still unwritten as to how this all going on sort itself out.

All right. That’s very helpful guys. Thank you.

Thanks Ben.

Thank you. The next question is from Robert Catellier from CIBC Capital Markets. Please go ahead.

Just want a quick update on your thoughts with respect to the new project approval process. In particular, how you might put development dollars at risk given that there’s new uncertainty related to that. And if you can specifically comment as to whether or not that will apply to the recently announced NGTL expansion?

I’ll make sort of the macro comment, devil is in the detail we obviously know, we just announced the other day, it’s open for comments, theory, faster approval times, one-stop shopping for regulatory approval, all directionally positive but the devil is in the detail is to whether or not the process can actually deliver on those kind of promises. So will participate in that process, and you will see. I wouldn’t view projects like LNG following into that major projects category but maybe Karl, you might have a view on that as well?

Well, my expectation is it would not. We have announced $2.4 billion expansion of the system, but you have to understand that is an accumulation of many different looping projects and compression projects that each one alone will be for a fairly small size. So I would expect this would be a series of smaller projects that even if this new regulatory regime is inactive, it would still fall under the smaller projects that would be – they really haven’t changed much given what I read in the proposal so far.

That impacts it’s reversing existing geography you’re revamping existing facilities. It doesn’t feel like that’s the intent but we’ll participate in the process they’ve asked for comments in regard to what projects should fall in here and certainly, our view that it’s not necessary for these projects to fall into that category.

Okay. That’s my question. Thank you.

Thanks, Rob.

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

All right, good afternoon. Just one quick question for me. At your Analyst Day you talked about building potential Permian gas pipeline, is there any updates on that front and I guess, just how do you see the competitive dynamics in the market right now?

Yes. So this is Stan. Big picture wise with respect to origination opportunities. Our team is working on about $1.5 billion worth of origination projects going forward. Some of these are longer puts and others but do you expect us to compete and win more than our fair share going forward. The details to your question are somewhat commercially sensitive right now. So I can’t get into them. But I will tell you this, we are leveraging our existing pipeline network by working closely with Karl and his team in Canada to provide outlets for Western Canadian producers to the Northwest into the Midwest. We’re looking at adding new demand centers to the Mid-Atlantic off of the Columbia gas pipeline and to your question in particular, we are looking to fill in some of the white spaces particularly in Texas. We want to be very thoughtful about what we do going forward. We want to remain true to our risk preferences. We are very quietly trying to see if we can put together a project that has long-term contracts with the portfolio of largely investment-grade counterparties returns that work for us. So I would ask that you bear with us for a little bit and that we will definitely update you as further details mature over the next several months.

Got it. Thank you.

Thanks Praneeth.

Thank you. The next question is from Andrew Kuske from Credit Suisse. Please go ahead.

Thank you. Good afternoon. I guess the question really revolves around just deploying capital into two of your major basins and read the Marcellus versus the Montney. And how do you think about the deployment of capital in those two markets and one thing that just jumped out of your release this morning is the contractual terms that you’ve got for the capacity of 28.6 years. And so how do you think about that on a risk-adjusted basis for returns relative to places where you can’t get those contractual terms?

I’ll maybe get start and then Karl and Stan can jump in. I think I gave you our answer and questions sort of outlook so we believe that these two basins are the lowest cost base in basins in North America. We’re seeing them both continue to grow as others decline. We don’t know yet how low the price can go and then still recover your full cycle decent returns on investment, but it appears to be something sub-$3 and maybe lower as they continue to prove out and get better and better at what they do. I guess our view is that those two markets, if you think of the North American market being around numbers of 100 billion cubic feet a day and then you’ll add on to an export capacity some increased demand for power, industrial demand, you’ll add of export to Mexico, people are talking about market that looks like 120, 130 more Bcf a day. These basins have the ability to continue to grow and that’s what on top of that 5 billion cubic feet a day of decline every year from traditional sources. There’s ample room for them to both continue to grow. While we’re making our capital investment first and foremost is the fundamentals. We think fundamentally, that’s a strong investment to move from the lowest-cost basin to market is going to be fundamentally sound no matter who own it’s, no matter what the term of contract. And then as we’ve seen, the term of contract in both places has increased, you think of how we can build up ANR, for example first prior to Columbia with contracts that averaged – if I remember correctly, somewhere in the 23 or 24 year range. GGN I mean that same sort of 20 plus year range, Columbia in that sort of same long-term range. The creditworthiness of these counterparties is improving. What we saw versus small producers, they still made the sub-investment-grade producers but they have multibillion balance sheets today with great provisions for future growth. So we tend to combine all those things together, we’re actually not making a choice currently a capital allocation decision between the basins. We think they’re both strong places to invest going forward. And as we always – Stan said we’re very careful about how we contract and what our paper looks like. But I don’t see it as a choice. I think they’re both strong fundamentally. The folks who are working with are getting stronger and as I look at our position going forward, there’s going to be ample new opportunities to add to that. I don’t know, you want to add to that Stan or Karl.

Yes. This is Stan. I’ll just give you color commentary with respect to Appalachian basis in our project. If you think of Appalachia as producing somewhere north of 25 Bcf a day today growing to 40 Bcf by the end of the next decade. And in support of that, I would note that we recently on January 1, put our Leach Xpress project into service at 1.5 Bcf a day of capacity, which today is flowing at just over 1.4 Bcf a day. So it just goes to show that there’s plenty of production out there to fill up expansion projects going forward. That’s an environment where if you look at the forward price on the NYMEX, it’s hard to find a lot of threes out there. Gas prices on the forward strip or sub-$3 for the most part, which is good to the extent that, that’s going to track new demand, new demand in the form of LNG exports. That’s one of the key signpost that we are going to continue to watch forward – going forward is the growth in LNG exports, which we believe could get up to that 6, 8, 10 Bcf a day over the next three to five years, so continued growth out of the Marcellus. Now we’re going to put somewhere around $4.3 billion of new capital investment in service later this year, which is going to be close to up to 4 Bcf a day capacity and I have every expectation, but that’s going to fill up not unlike our Leach Xpress project did.

Maybe I’ll just make a comment as well. We talked a lot about when we went to up disposition in the Marcellus and why the Columbia assets were such a great fit for us and when I viewed the work that we got ahead of us and the business that we get ahead of us, I don’t see it as an either or as a capital allocation decision at all. I think both we’re sitting on two of the best resources in North America and I think that they’re very, very complementary. And as a matter of fact, when we work together, I always considered the our lack of position in the Marcellus and Utica to be a big competitive disadvantage for us. So when we take a look at what we have done, our markets have been impacted by the WCSB markets have been impacted by Appalachian gas. When we didn’t have a position in it, we lost some of our U.S. Northeast markets. We’ve seen Rover, we’ve seen come Nexus into our Dawn market. We have seen back in the Bakken associated gas decrease the mode of WCSB gas goes down in the northern border. So yes, I guess when I would say we have still lots of work to do and I just don’t see any issue between allocated capital between the two and both of these basins are competitive and I think that if we are not working in one, that gas will still move so I think we’ve got to be very mindful of that just because we choose not to move the gas doesn’t mean it won’t move and it won’t move in the markets that compete with us. So I think we’re quite eager to make sure we maintain our market share in both areas.

And maybe if I can, Karl, well you are on the role on this topic. Do you foresee the possibility on the future of have an integrated tolling offering on Nova system and the Mainline on a long-term contracted bases to hit Dawn or even further than Dawn?

Well, I don’t think it’s a secret that I’ve been for many, many years. Now I’ve been out talking about the advantages of rolling the Mainline into NGTL well. And I actually did that in a hearing once – I didn’t, it was all that successful and hearing but those were different days. And I have been – I am out on the stump again, in the market here. We’re talking to the producers, giving them some of the benefits of merging these two systems in the competitive business benefits, especially to accessing and keep some of our markets down east. On the other hand, I’ll just give – I’ll end discussions just going on a very high level discussion of why we think it works pretty well. Number one is, by the time we are finished our NGTL build out at least the phase of it, we are going to see and NGTL system probably had about $12 billion of capital in it. By the time, we finish in 2020, our LDC settlement, we’re going to see Western System on the Mainline. It’s going to have about $1.3 billion in it. So we just take a look all large numbers. It really makes sense for a competitive WCSB to put the Mainline into NGTL and make it part of the NGTL tolling structure. It’s just – you just get far more billing determinants in NGTL than we developed in the Mainline to keep the tariffs where you want them to. My preliminary numbers suggests we can move the actual ongoing day-to-day tolls and this is all depends upon tolling design. But this is just indicative we can decrease the toll to get to the Eastern market either North Bay, which has been the Dawn equivalent, I would think. We can increase or decrease that tolling by 30% to 45% depending up on all the methodologies that we would use to emerge in the two systems. So yes, I’m going to continue talking to our producers to see if I can’t commence they should take this seriously. And I do think it’s the right thing to do.

I think so too.

Thank you. The next question is from Ted Durbin from Goldman Sachs. Please go ahead.

Thanks. So I’d love to stay on this topic and actually ask around the next wave of volumes on the Mainline, which be willing to do discounted tariffs to sort of producing community like you did of the 1.4 Bcf a day that you announced last year in order to attract more long-term commitments?

This is Karl, again. Yes, we were actually look at that right now. Where we have to be realistic about what type of product that we can offer. The last product that we offered we had huge supply overhang. We are clearing a very large surplus, and that we’re very successful in clearing that and making sure that the remaining capacity is viewed as some value for the rest of the industry, which I think we’re very successful at. This next tranche, what we want to do is we want to sell some of the capacity that we believe is going to come up with the non-renewals, and we want to, if we can, we want to bring some of these dormant capacity out of dormancy, so to speak, and get it ready for back end service and our longer-term basis. So I think we are working on this right now or not only our community producer committee but actually some of the markets out of the end of the pipeline are asking us what we can do and what the terms and condition could be. So I think you will find us. We’re working on as I speak, I do not have a product right now to put in front of our customers, but we are working on it as I speak and I do believe we’ll be able to put a long-term fixed price product in front of them. But I would just caution you, it may not look exactly the same as last one we did and the prices certainly won’t be the same, but we are working on the product.

Got it. I think it’s helpful. And then sticking with the producer restrain for pipeline tolls, if you think that the West Coast LNG, one of the hang ups, of course, it’s been the cost of the pipe. Is there any discussion around having the producing community maybe where a portion of that cost of the transportation that have been just developers or the buyers that would pay for that?

Yes, actually, there’s been lots of discussion both from various groups of producers, governments, you name it, on what the NGTL System can do to use this have to help that cost. We haven’t seen anything – nobody has actually come to us with any type of real plan, so to speak, to roll it into the NGTL System or anything like that at this time. As far as, we are concerned given our experience from a regulator, that will be a very long pipe in order to do that. But having said that, this is a – I do viewed this as essentially a producer pipeline system and if the producers are willing to pay for this, or piece of this to be rolled in. I’m always – opened to that discussion and open to collaborating with the producers. But as of right now, I would say there is nothing concrete on the ground just talk about, how would be nice if we did, something like that could happen and looks like it’s a long way off.

Yes, as it’s just to be clear for the Coastal GasLink Canada LNG project that the pipeline tools haven’t been an issue. Our understanding talking to the sponsor Shell and its partners, the issues have been market, I mean, market window. They believe another market window is on the horizon at 21%, 22%. We look at the combined sort of cost from our math and it appears it’s competitive, I think so that’s was one issue. The other one was capital availability and capital allocation within Shell and I think a couple of years ago, they announced that due to lower capital availability they weren’t just – they couldn’t proceed with several major projects at one time and but that LNG Canada was still highly ranked within their company. As crude prices return they finished other projects we believe it’s still high-priority for capital allocation within Shell. So I think those are the major drivers and sort of we’re not getting any – what with their vast sharpen our pencil certainly around our costs for building our pipeline but that won’t be a major driver I think of that FID decision. It will be I think one based on Shell and its partners outlook of their capital availability and end markets.

That’s great. I appreciate all the color. Thank you.

Thank you. The next question is from Tom Abrams from Morgan Stanley. Please go ahead.

Thank you and thank you for this all information, it’s a auto-process. Just remaining for me was about Mexico and if it is much as Mexican gas demand is taking a lot – kind of queue up if there’s any chance that your project there would be delayed or if payment from CFE would be different than what you would originally thought?

Hi, Tom, it’s Karl. No, we haven’t – actually, the projects are the ones that are being delayed there right now, not the access to gas and the need for gas. I would know the CFE has many power still running at fuel, but which we’re not running fuel. So our expectation is that as it assume we bring our plants in the service, they will be utilized as per the plan from CFE. As per kind of our financial arrangements, these are take or pay contracts, the CFE is a great credit and it’s – we don’t see any issues even if the plan was slower than what they had hope for, but right now, I’m quite comfortable with the strategy. Most of the gas pipelines right now are built for our power plants that are entering in the process of being built or already build and running on fuel oil. So there will be – once these pipelines are put in service, you will see them operate at a reasonable that the low factor that was predicted by the CFE at the time they tend to.

Great. All right. That’s it. Thanks a lot for all your time.

The next question is from Naqi Raza from Citi. Please go ahead.

Thank you. Just a couple of quick questions. In terms of just contracting on Marketlink, when you went out with your open season on Keystone, you also included Marketlink. But are we to assume that until Keystone XL doesn’t come online, Marketlink is essentially very low level of contracting take or pay from commitments on that line.

Nick, it’s Paul here. We did go to an open season late last year, and we did secure additional contracts on Keystone takes us up to 550,000 barrels per day, which means Keystone is about in excess of 90% contracted. When you look at Marketlink, we do have space required for Keystone XL. We went up, went out earlier this year and termed out some of that space. And when you look at it from a contracted perspective, probably about 80% of our capacity is locked down under contracts that we put in place here just over the last couple of months.

And those are pre-Keystone XL, correct?

Yes. Thank you for that. That’s what I was trying to get to. The pre-XL, we do have restriction on that space, so as limited how much we can term up, but we termed, fair to say, we termed up what we could. We managed to term up about 80% of the capacity. So when you look at the total EBITDA for the liquids pipelines, above 85% – 85% plus is now locked down by contract.

Fair enough. And just turning really quick to Karl’s comments on Mexico. In terms of any CapEx overruns, are we to assume that those are essentially passed on to the shippers or are those something that TransCanada would serve there?

Well, it would dependent and how the over run was realized. Under our contracts with the CFE, if we have a costs associated with the force majeure event, that would be deemed to be the governments – the government be in the reason of the force majeure event, examples of those will be the government is responsible for indigenous consultations and if those are slow or other parts of the force majeure that are responsibility of the government to take care of. Then, we would pass those costs increase through to the CFE. We’ve had a couple of these before in the past, sometimes they get passed through the toll, sometimes they get settles with the financial settlement, sometimes they get settled with an incremental deal. But force majeure events that are – the force majeure and the cost increases are a result of government action are generally pass through to the CFE to the government of Mexico. Any cost increases that happened outside of those conditions would be the responsibility of TransCanada. And we would add those costs to our rate base, because we do actually, we will have third-party volumes on there, and we can’t collect those cost increases, other volumes have move on the system. So our regulatory rates, so to speak in Mexico will go up and then can takeout those cost increases.

Fair enough. That’s great color. Thanks guys.

Hey, thanks.

Thank you. The next question is from Matthew Taylor from Tudor Pickering. Please go ahead.

Yes. Good afternoon guys. Thanks for taking my question. Just a quick follow-up on Karl’s earlier comments. Contracts are stepping down in 2020 and 2021 room on the Great Lakes seems like there’s an opportunity to get Canadian volumes down to the U.S. Gulf Coast through a potential call it may maybe an ANR reversal or something else. Can you just give me some thoughts on what checks for markets you’re focused on with the Mainline going forward?

Maybe, I could say this and I can let Stan jump in, because Stan is the one working most of these. But we – you won’t see a tariff from us that we would grow to market with continuous path about question, you’ve got Canadian pipelines, and you got U.S. pipelines, but a customer is certainly, if we have the capacity or if we could build the capacity quite frankly, customers are – we will market customers and market customers are free to come to us and asked us to look at different pass for them to see if we can move their product. As I’ve said before, we can get only on the Gulf Coast, and et cetera for small blank spaces, we can get only in Mexico City on theoretically if people wants. So people are free to come talk to us, I know we will be marketing to people. But it won’t be as simple contiguous tariff, the U.S. would have to kind of put together Canadian tariff and Great Lakes tariff, and Mainline tariff, that sort of thing, but that certainly is possible and I know there are people have talked to us in the past and maybe I’ll pass it over to Stan, he can talk about any borrow of the plans he has on them.

Yes. I think you question is a good one. Really highlights the need for Karl’s team and Canada and my team in the U.S. through closely together, big picture wise, we do have a general available capacity on the Great Lakes systems, so to the extend there’s another LTF2 type deal. We would welcome the opportunity to fill that system up. We also have the ability to expand the ANR system fairly economically to the tune of that 0.5 Bcf a day or so into the Chicago area. And above and beyond that, with respect to incremental capacity down to the Gulf Coast on ANR staff this Mainline to a large extent, that would be a build. We do have small pockets of capacity availability that we’re looking to potentially place with one counterparty. But do note that as part of the Marcellus buildout, the ANR did enter into significant amount of contracts as part of its rate case, half of which goes south to the Gulf Coast already. So a big chunk of the historical or general available capacity on the ANR system is spoken for and spoken for term of about 30 years.

Yes. That’s great guys. Thanks for the color. And then just one more, moving over in North Montney, is there any kind of a read-through from the export announcement [indiscernible] proceedings or at least strengthen your positioning in providing more ingress for shippers to clear the increased receipts from the North Montney?

Sorry, I didn’t get all that, but I assume the question was there was some concerns that we’re bringing more supply on that market, and that was a big complaint of some people from the North Montney. I guess, I would say this about that issue. Number 1 is not TransCanada’ s role to sit there and judgment of what people are going to market their gas. So the last thing I think the producers want in the market, is for TransCanada to decide who brings the gas on and who doesn’t. That type of supply management is just not a wrong. I think nobody wants anybody to play that role. So from TransCanada’s position, we want to provide everybody an opportunity to compete. We are providing ingress out of the market. One of the issues that we do that is the way the system works is, supply comes on, supply sees us an opportunity, the price differentials get wide and there’s an opportunity to buy export capacity to get to market and then they buy export capacity. So it’s kind of a linear path that you’re not so exactly what we have seen. As Russ said in his opening remarks, we have put in place right now between now and 2020 – to 2021, we put in place a 2.2 billion cubic feet per day of new market opportunities, both in the down, down south through GTN and so the Pacific Northwest of California out into Empress, which ultimately go into east and even internal to NGTL System. So and on top of that, we had natural decline of our system, which is running couple billion cubic feet a year. So I don’t think – you have to be careful when you start, when you start trying to micromanage a system like ours as to what supply comes on and which supply does not come on. That supply, if we do not bring it on North Montney I will say, it will produce and it will compete with everybody else on our system, anyway it just will not produce in our system, but we will not get the billing, so our customers will have to pay higher tolls. And that’s the unfortunate result if the board does choose to go with the people that say we should not bring that gas on. So I guess you can tell I have very strong feelings about this, but with limiting supply is not an answer. Actually, I would argue that what the system needs right now, because more transportation capacity not less.

Thanks guys, that’s helpful.

Thanks Mathew.

Thank you. The next question is from Joe Gemino from MorningStar. Please go ahead.

Hi, guys, thanks for the time. When you think about the Keystone and Keystone XL when it’s fully ramped up, how do you think about capacity and where will it go? Will all of the legacy capacity go to the Midwest and all the XL go to the U.S. Gulf Coast? Or is there some other type of mix that you can elaborate on?

Hi, Joe, it’s Paul here. Once we bring XL into service, we will move contracts that flow in XL today that convert XL contracts over on to XL and I would anticipate XL will really be a hardest to let’s call it Cushing and Gulf Coast pipeline. And then the existing Keystone mainline will kind of serve that Midwest market into Illinois.

Great. And is there any opportunity for the existing Keystone pipeline now to go down to the Gulf Coast or do you think it’s fully going to be in the Midwest and Illinois?

Right now, you mean?

No. when the Keystone XL is brought online and fully in service.

No. When the Keystone system, including the XL project is fully built out, the XL Lake will be the sole transportation, if you wish, to the Gulf Coast. And will lines will effectively had a bullet line from the North to the Gulf Coast on the XL project and then we’ll have a second bullet line, again, from Hardisty into the Midwest. We would have opportunities in the future, assuming demands there. And we can underpin it with contracts to loop our Cushing extension, which is the line today, which runs from Cushing down to the Gulf Coast, I’m sorry, from Steele City down to Gulf Coast. And that would provide the Gulf Coast access of the existing legacy Keystone system as well. So right after we hit in service, consider it two bullet lines one to the Gulf Coast, one to the Midwest, but as supply builds as demand grows, we do have expansion looping opportunities so that we can compete the Gulf Coast from the legacy system as well.

Great. I appreciate that.

You’re welcome.

Thanks Joe.

Thank you. This concludes today’s question-and-answer session. I would like to turn the meeting back over to Mr. Moneta.

Okay. Thanks very much. And thanks to all of you for participating today. We very much appreciate your participation during what we know is a very busy time for you. We look forward to talking to you again in the not-too-distant future. Bye for now.

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