TC Energy Corporation
Q4 2016 Earnings Call Transcript

Published: 17 Feb 2017

[Operator:]

All participants, thank you for standing by. The conference is ready to begin. Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2016 Fourth Quarter Results and Business Outlook Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President-Investor Relations. Please go ahead, Mr. Moneta.

[David Moneta:]

Thanks very much and good afternoon, everyone. I'd like to welcome you to TransCanada's fourth quarter 2016 financial results and business outlook conference call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Alex Pourbaix, Chief Operating Officer; Karl Johannson, President of our Natural Gas Pipelines business; Paul Miller, President-Liquids Pipelines; Bill Taylor, President of Energy; and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some comments on our fourth quarter financial results as well as our business outlook. With respect to our outlook, similar information would've been covered at our Annual Investor Day last November. As a result, our comments this afternoon are expected to last approximately 45 minutes or 50 minutes, which is longer than normal. While lengthy, we hope you will find the added information beneficial. The slide presentation that accompanies our remarks can be found in our website in the Investors section under the heading Events & Presentations. Following Russ and Don's remarks, we will turn the call over to the conference coordinator for questions from the investment community. If you are a member of the media, please contact James Millar 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 added questions, please reenter the queue. In the interest of time, if you have detailed questions relating some of our smaller operations for your detailed financial models, Stuart and I would be pleased to discuss them with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian securities regulators and with the U.S. Securities Exchange Commission. Finally, during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, comparable earnings before interest, taxes, depreciation and amortization or EBITDA, comparable funds generated from operations and comparable distributable cash flow. These and certain other comparable measures do not have any standardized meaning under GAAP and are therefore considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. They are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations. A reconciliation to the nearest GAAP measure is included in the appendix. With that, I'll now turn the call over to Russ.

[Russell K. Girling:]

Thanks, David, and good morning everyone and thank you very much for joining us today. (sic) 2016 was truly a transformational year for us here at TransCanada as our portfolio of high-quality energy infrastructure assets performed very well, while our long-term strategy of national discipline enabled us to undertake unprecedented growth that will reward our shareholder for many more years to come. Our $13 billion acquisition of Columbia represented a rare opportunity to further diversify our regulated natural gas pipeline and storage operations, and gave us an incumbency position in the Appalachian region, which, as you know, is one of the world's fastest-growing and lowest cost natural gas production basins. We now own and operate one of North America's largest natural gas transmission businesses with a strong competitive position in the fastest-growing supply regions of North America. We also agreed to acquire the outstanding publicly held common units of Columbia Pipeline Partners were for $17 per common unit or approximately $915 million. I'm pleased to report that earlier today, the Columbia Pipeline Partners' unitholders approved the transaction and as a result, we expect to close the acquisition in the coming days. This will result in 100% ownership of Columbia's core assets and will simplify our corporate structure. Over the past year, we have added CAD 13 billion of projects to our near-term commercially secured growth portfolio, the largest addition came through our Columbia acquisition, which included over CAD 7 billion in long-term contracted expansion and modernization projects. We also added two additional natural gas pipeline projects in Mexico that will see us invest an additional $1.9 million in that region as well as ongoing expansions of our NGTL System. To help fund the Columbia acquisition, we decided to sell our U.S. Northeast power business and subsequently we entered into two separate sales agreements, which are expected close in the first half of 2017. We're also in the process of monetizing our U.S. Northeast power marketing business. In total, we expect to realize approximately $3.7 billion, which will be used to retire the remainder of our acquisition bridge facility. During the year, we raised approximately CAD 11 billion of subordinated capital through the issuance of common and preferred shares as well as hybrid securities. This allowed us to permanently fund the Columbia acquisition and maintain our A grade credit ratings. Looking forward, these actions are expected to be accretive to both earnings and cash flow per share and drive significant shareholder value in the years ahead. Before I provide an update on our business outlet, I'd like to make a few comments on our fourth quarter and full year 2016 financial results. Excluding certain specific items, comparable earnings for the fourth quarter 2016 were CAD 626 million or CAD 0.75 a share, an increase of CAD 173 million or CAD 0.11 per share over the same period last year. Comparable EBITDA increased CAD 363 million to approximately CAD 1.9 billion, while comparable funds generated from operations were CAD 1.4 billion and were 16% higher compared to the fourth quarter of 2015. For the full year, comparable earnings were CAD 2.1 billion or CAD 2.78 per share, an increase of CAD 353 million or CAD 0.30 per share over 2015. This equates to approximately 12% increase on a per share basis. Comparable EBITDA increased CAD 739 million to approximately CAD 6.6 billion, while comparable funds generated from operations exceeded CAD 5 billion for the first time in our history. Don will provide you more detail on our financial results in just a few moments. Based on the strength of our financial performance and our growth outlook, TransCanada's Board of Directors today declared a quarterly dividend of CAD 0.625 per common share, which is equivalent to CAD 2.50 per share on an annual basis. This represents a 10.6% increase over last year and it's the 17th consecutive year that the board has raised the TransCanada dividend. At the same time, we have maintained very strong earnings and cash flow payout ratios. Turning now to slide 8, I'll provide a few comments on our outlook for the future. Since 2000, our strategy has essentially remained the same as we have invested approximately CAD 70 billion in high-quality, low-risk growth opportunities. That investment generated significant growth in earnings and cash flow and contributed to a 14% average annual return for our shareholders. Today, our CAD 88 billion high-quality portfolio of critical energy infrastructure assets includes natural gas pipelines in Canada, the United States and Mexico, as well as liquid pipelines and energy assets in both Canada and the United States. Following the monetization of U.S. Northeast power business, over 95% of our EBITDA will come from regulated or long-term contracted assets. As a result, our assets are well positioned to produce solid, steady results through various market cycles. They also provide us with multiple platforms for continued growth. Today, we are advancing CAD 23 billion of near-term growth opportunities that include a series of projects in jurisdictions where we see relatively normal course permitting and construction capability. We also continue to advance over CAD 45 billion of long-term growth opportunities. Any one of these large scale initiatives would create significant incremental shareholder value and position us for continued long-term growth. As a result, we expect the annual dividend growth in the upper end of 8% to 10% dividend range through 2020. And finally, we have maintained a solid financial position. Our A grade credit ratings allowed us to access significant approvals of capital at lower cost than most of our competitors and provide us the ability to act at all points in the economic cycle. We also believe that a simple and understandable corporate structure is a competitive advantage and does differentiate us from many of our peers. Turning now to slide 9, as I mentioned, TransCanada is focused on three core businesses in three core geographies. We own and operate one of North America's largest natural gas transmission systems with over 90,000 kilometers or 56,000 miles of pipeline that connect the fastest-growing basins to the key markets. Today, our pipelines transport more than 25% of the daily North American demand. We're also the continent's largest provider of natural gas storage with 653 billion cubic feet of capacity in liquids. Our 4300-kilometer Keystone system transports 545,000 barrels of crude oil per day or approximately 20% of Western Canadian exports to key refining markets in the U.S. Midwest and Gulf Coast. We also currently own or have interest in 17 generation facilities with a capacity of approximately 11,000 megawatts. Following the sale of our U.S. Northeast power business, we will still be one of Canada's largest power generation companies with over 6,000 megawatts of long-term contracted power generation. Over half of that capacity is comprised of emission-less power including nuclear, wind and solar. Our remaining capacity consists of high-efficiency natural gas power generation facilities. Looking forward our CAD 23 billion of near-term commercially secured projects will expand our footprint across North America. It includes approximately CAD 19 billion of natural gas pipeline expansions that are driven by growth in North American natural gas supply in the Marcellus and Utica as well as the Western Canadian Sedimentary Basin, along with demand in growth in places like Mexico. We're also developing a regional liquids pipeline system in Alberta with CAD 2 billion of projects expected to enter service by 2018. And finally, we're advancing another CAD 2 billion of power projects, including the 900 megawatts Napanee gas-fired plant in Ontario, as well as the initial work required at Bruce Power as part of the multibillion-dollar life extension agreement with the Ontario Government. We've invested approximately CAD 6 billion in these projects to-date with remainder to be spent over the balance of the decade. Notably, all of these projects are underpinned by long-term contracts or rate-regulated business models. As a result, we have a high degree of visibility to the earnings and cash flow that they will generate as they enter service. Over the next few minutes, I'll expand on these projects and the additional organic growth opportunities that we expect to surface from the extensive North American footprint that we now enjoy. So, starting with Columbia, we spent the last six months integrating our operation with our U.S. pipeline business. That process has gone extremely well and we expect to realize a significant portion of the CAD 250 million in targeted benefits in 2017, with the remainder to follow in 2018. On the growth side, having completed certain modernization projects in 2016, Columbia's capital program now include $7.1 billion of projects that are largely expected to enter service by 2018. These projects are also proceeding according to the plan. We recently received FERC permits on two of the larger initiatives

[Donald R. Marchand:]

Okay. Thanks, Russ, and good afternoon everyone. During the next 25 to 30 minutes, my intent is to briefly touch on the fourth quarter results and provide an overview of our financial outlook, including our capital spending and related funding plans, comparable EBITDA growth, and finally dividend growth and related distributable cash flow payout ratios through 2030. First, the highlights of our fourth quarter 2016 financial results. As outlined in our financial highlights news release issued earlier today, we've reported a net loss attributable to common shares in the fourth of CAD 358 million or CAD 0.43 per share, compared to a net loss of CAD 2.5 billion or CAD 3.47 per share for the same period in 2015. Our results included a non-cash after-tax loss of CAD 870 million related to the monetization of our U.S. Northeast power business, an additional CAD 68 million non-cash after-tax charge to settle the termination of our Alberta PPAs, an after-tax charge CAD 67 million for costs associated with the acquisition of Columbia and certain other specific items. Fourth quarter 2015 included a CAD 2.9 billion non-cash after-tax impairment charge related to Keystone XL as a result of the previous U.S. Government's decision to deny our request for a presidential permit in November 2015 as well as certain other specific items. Excluding these items, comparable earnings for fourth quarter 2016 rose by CAD 173 million to CAD 626 million or CAD 0.75 per share compared to CAD 453 million or CAD 0.64 per share in the same period last year, a 17% increase on a per share basis. Turning to our business segment results at the EBITDA level on slide 25. In an effort to continuously improve our disclosure, we have split Natural Gas Pipelines into the three separate segments under the invented monikers of Canadian, U.S. and Mexico natural gas pipelines. There are no changes to our other two segments, Liquids Pipelines and Energy. In the fourth quarter, comparable EBITDA from these five businesses is approximately CAD 1.9 billion, was CAD 363 million higher than the approximate CAD 1.5 billion reported for the same period in 2015. The increase was largely driven by the following factors

[David Moneta:]

Thanks, Don. Just a reminder, before I turn the call 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, we'd ask you to please re-enter the queue. With that, I'll now turn the call back to the conference coordinator.

[Operator:]

Thank you. We'll now take questions from the telephone lines. The first question is from Linda Ezergailis from TD Securities. Please go ahead.

[Linda Ezergailis:]

Thank you. Thanks for the comprehensive business update. Looking at Keystone XL, I see you filed again in Nebraska today with an expected completion in 2017. Can you give us an update on your assumptions around key work streams, including beyond the regulatory process a timeline on commercial discussions and when you expect to complete that as well as your cost estimates updated along with your engineering work and when you might be able to start construction?

[Paul Miller:]

Linda, it's Paul Miller here. I've got down here commercial discussions cost estimate timeline. So I'll answer those, and if I miss anything please remind me. Our first course of action here is we are engaged with our shippers. There's a lot of interest in Keystone XL as a result of the presidential memorandum. So we're working through the shipper group and they're working through their analysis, but a lot has changed since November 2015, when Keystone was denied the presidential permit. So it is going to take some time for these shippers to assess their volume commitment. There is a sense of urgency on their part, but they do have their governments to go through. On the cost side, $8 billion is our most recently prepared cost estimate. I would anticipate we would look to be fleshed out sometime during 2017, but our cost estimate at this point is the $8 billion. And as far as the timeline goes, we follow the Nebraska application for the route through Nebraska with the Public Service Commission today. That process could take the better part of 2017 to conclude. I would anticipate towards the end of 2017 and 2018, we would have various permits that we would require. At that point, we would start to do some of the staging activities that you speak of. I would not anticipate we'd be ready for construction until well into 2018, and that construction process, although we're still going through the implementation planning right now, is the better part of two years plus.

[Linda Ezergailis:]

Okay. So if it's later into 2018, you'd miss one of those construction windows so it would be – okay. Just a follow-up maybe on – just stay in the U.S. on tax reforms, has TransCanada started to run some sensitivities and scenarios around what might happen if interest expense deductibility and changes in deductibility of capital investments are implemented along with the reductions in corporate tax rates and what the net effects might be on your business?

[Donald R. Marchand:]

Hi, Linda. It's Don. The simple answer is no. We haven't run any quantitative sensitivities at this point in time. We're monitoring like everybody else, and to look at any of these things in isolation and versus what a package might ultimately look like in a phase in period is just really difficult. So as there's more and more definition put in on how this might play out, we'll start doing that but at this point we're just in the monitoring phase.

[Linda Ezergailis:]

Okay. Thanks. Will jump back in the queue.

[David Moneta:]

Okay. Thanks, Linda.

[Operator:]

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

[Robert Kwan:]

Good afternoon. Just looking at the financing plan, you talked about it being geared to maintaining the credit rating, and Don you mentioned 15% FFO to debt. I'm just wondering, is that a discussion you've had with S&P or how do you think about the 15% versus the 18%?

[Donald R. Marchand:]

Yeah, at this point, I – just looking back at what we've done here, we've added CAD 11 billion of subordinated capital over the last year, changed the business position in our view substantially for the better by selling our merchant assets and we see 95%-plus EBITDA coming from regulated cost of service businesses going forward and achieving certainly 15% FFO to debt and 5 times debt to EBITDA in 2018. So I guess I best direct this at S&P as to how they would weigh the quants versus the qualitative side of this going forward. So yeah, we're on track in 2018 to hit 15% and 5 times, but I'll defer to discussions with S&P as to where they weigh the quants versus the qualitative.

[Robert Kwan:]

Okay. And I guess if I can just turn to the Mainline and you've been as you've acknowledged in discussions with potential shippers. Have you had any either formal or informal discussions with other parties who will likely be interested in this? And I guess I'm just wondering if you've assessed the risk on the intervention side, just given what you've already seen on the much smaller Herbert LTFP service.

[Karl Johannson:]

Thank you, Robert. It's Karl. Yeah, I understand your question. We have been keeping all of our customers up to date in terms of what we're thinking on what a load attraction deal would look like. I am expecting if we do come to agreement, and as Russ said we're encouraged with the discussions but we haven't come to agreement. I'm expecting we'd have more conversations with them. But yeah, as you said we're experiencing with the smaller load attraction rate in Saskatchewan. I would expect there would be some questions and some opposition to it in hearing. And I believe that our – any deal that we will strike, we would strike it with the idea of making it reasonable for regulators to see the benefits of the system. So we're willing to – we're expecting some opposition as we do go forward and we're willing to put our case forward that is good for the entire system.

[Robert Kwan:]

That's great. Thanks, Don. Thanks, Karl.

[David Moneta:]

Thanks Robert.

[Operator:]

Thank you. The next question is from Rob Hope from Scotiabank. Please go ahead.

[Robert C. Hope:]

Yes. Good afternoon. Just want to circle back on Keystone XL and just on your conversations there with shippers and the timeline there. Just want to get a sense of your understanding of the need just given the fact that we also do have TMX potentially on the go as well as line three. Are you looking to potentially be later on in the next decade to potentially accommodate TMX, or do you see a need for a number of pipelines?

[Paul Miller:]

Hi, Rob. It's Paul here. I think there's various projects out there doing various stages of development and various degrees of uncertainty. And I think it's important to remember that these pipelines or these proposed pipelines, they will serve different markets with different shipper groups and it's not an industry-led approach to pipeline capacity and planning. So our business model answers the shippers' call onto what market they want to access. Shippers will make a call on the market that they want to access with their supply. In the case of Energy East, for example, it's the Eastern Canadian refinery market pad 1 and pad 3 in the international markets. And in the case of Keystone XL, it's the U.S. Gulf Coast. So our business model supports these choices that the shippers make that providing the secured access to the markets of their choice, and this is supported by and taken out long-term take-or-pay contracts on our pipeline. So we will meet whatever our shipper group requirements are in regard to implementation of Keystone XL.

[Robert C. Hope:]

All right. That's very helpful. And then just looking at your long-term EBITDA outlook, you did mention that potential revenue benefits of adding the Columbia system with your other gas systems could be additive. Do you have any targets that you can share with us or a timing of when you can start realizing revenue synergies between TransCanada and Columbia system?

[Karl Johannson:]

Yeah. Hi, it's Karl again. Yeah. Obviously, we're working on that as we speak on how we can interconnect these systems and get flows going in between systems. We don't have any answers right now. The reason we never published this was, again, because they're kind of a sub – they're three years out. They're not within the range of the initial CAD 250 million a year that we published. They generally require some construction prior contracts with our customers. So we are working on that. We expect it to be – we expect there to be some synergies there when we get these physical systems interconnected. But no, at this time we haven't put out any number of what we expect to realize from them.

[Robert C. Hope:]

Thank you.

[David Moneta:]

Thanks, Rob.

[Operator:]

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

[Andrew Kuske:]

Thank you. Good afternoon. Obviously, there's a pretty big wedge of EBITDA growth coming from the U.S. gas pipelines really in the foreseeable future. So I guess maybe the question is to Karl, it's just what have you seen and what have you noticed in, I guess, the first seven months post close of Columbia on just differences in customer behavior between those in the Marcellus and those in the Montney?

[Karl Johannson:]

Yeah. Hi, Andrew. This is Karl. It's an interesting question, maybe I'll start by saying this. I guess what I found in the Appalachian area is that the customers are far more willing to and far more comfortable with signing longer-term contracts to create gateway capacity. Obviously, you've probably followed our discussions with the producers out of the WCSP. And that's something relative new for them, they have been very used to producing and selling into net and not having to market those lines also, which I think is changing for them which is why we're spending so much time trying to do some more attraction deals. So I think one of the big difference is, the additive towards signing up for long-term contract actually towards backstopping a construction of the gas pipelines and so forth is one of the bigger differences that I've seen between the two basins. Having said that, I think our customer base in two basins is very much the same right now. When we look at NTTL, it's very much a producer driven system. When you look at the Columbia assets, it's probably about 46% now is producer driven, the rest is LBC. So we have similar customers there, some are requirements to get the production out and so forth. So the main issue would be just a comfort level we have taken the gas, moving it away from the production area and to the market area and then signing longer-term contracts.

[Andrew Kuske:]

Okay. I appreciate that. And then maybe just sticking towards on the Marcellus and just the Eastern Triangle area, it's very noticeable that the volumes on the Alberta, Saskatchewan side, 2.9 Bcf is what you've posted on an average basis through the year, and then 4 or 5 on the average of the system. So how do you think about just the changing nature of the Mainline and the ability now to a greater degree to really move volumes around the Northeast and the compounding of opportunities that happen off that, what are you seeing now that you're looking at this as a fully integrated system in the East?

[Karl Johannson:]

Yeah. I do look the East as being a fully integrated system, and I can tell you right now we're working very hard with customers out in the Northeast to market the Mainline as part of their Northeast gas supply strategy. There has been severe difficulty putting new Greenfield gas pipelines through the Northeast and into the New England, New York market area, and we think we have a great option to bring the gas up through Dawn and maybe through Chippewa or Niagara, and then move that through our Mainline – the Eastern segment of our Mainline out to Iroquois or PNGTS as Russ was saying earlier in his speech and then expanding those systems up. I think the pipe in the ground right now is very valuable to these customers that need incremental supply, so that's one of the priority marketing areas that we have right now is talking to both the LDCs and load and market in the Northeast area, and talking to the producers in Appalachian and WCSB and trying to match something through our Mainline into the U.S. Northeast.

[Andrew Kuske:]

. Okay. That's great. Thank you.

[David Moneta:]

Thanks, Andrew.

[Operator:]

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

[Ben Pham:]

Good afternoon. Just on that last comment about moving gas potentially into the Northeast markets (01

[Karl Johannson:]

I'm sorry, the regulatory issues with buyers moving gas under...

[Ben Pham:]

Just to some of the electricity distribution companies?

[Donald R. Marchand:]

I don't think there is any regulatory issues, clearly the companies we're dealing with right now, and we've actually quite far down perhaps with some companies. Clearly, they would have to get their own public utility commission's approval, then a big supply deal – a long-term supply deal that they would do. But I don't think those approvals aren't unusual for any type of transaction like that. And they are certainly not approvals that are needed just because they're using the Canadian Mainline assets vis-à-vis a local U.S. asset. So I guess short answer will be no. I have not run up against any regulatory impediment to doing a transaction like that, yeah.

[Ben Pham:]

Okay. And then on some commentary about the qualitative impact of merchant power assets, and I'm just wondering there is no commentary about additional merchant exposure going forward, and it looks like over time you could be almost sitting at pretty minimal commodity exposure. Your appetite for merchant power, would you say it's very low right now at the moment?

[Russell K. Girling:]

Hi. This is Russ. I can maybe take a shot at that at the corporate levels. At the current time, we see an opportunity to migrate our EBITDA to a more predictable stream. We see that the opportunity to invest our capital for the coming next number of years, CAD 23 billion of it, that can be invested in less volatile streams. So for the foreseeable future, that is the direction that we'll be going. As we said, we understand commodity risk very well, we've managed it extraordinarily well in the past but it's not something that we see a need to be involved with to any great extent for the foreseeable future.

[William C. Taylor:]

It's Bill here. Ben, I'll just add to Russ's comments and say that you shouldn't ignore that we have managed and continue to grow our energy platform in ways that aren't structured in the merchant manner. So the growth at Bruce, the growth at Napanee and some of the other activities that we've undertaken, we would expect to continue to try to land opportunities like that in the regions in which we operate.

[Ben Pham:]

Okay. That's helpful. Thanks everybody.

[David Moneta:]

Thanks, Ben.

[Operator:]

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

[Theodore Durbin:]

Thanks. Just on Keystone XL, you before said that you were looking for around CAD 1 billion of EBITDA on CAD 8 billion of capital, is that still the kind of return you're looking for on Keystone?

[Paul Miller:]

Yes. Ted, it's Paul here. The CAD 8 billion is our previous estimate, it was completed, I believe, back in 2014. So that's our current estimate. And then on the EBITDA, we're in the process now of firming up our commercial support in our commercial terms. So it's a little premature to provide any guidance on the EBITDA front but we would anticipate trying to achieve the type of returns we typically achieve on these type of projects in the 7% to 9% range; given the passage of time and some of our historical cautionary agreement with the shippers, I would anticipate being at the lower end of that range. But we don't have any EBITDA guidance at this point.

[Russell K. Girling:]

And Ted, as you know, the range that Paul is referring to, that would be after tax return on total capital as opposed to a return on equity, if you will.

[Theodore Durbin:]

Yeah. Understood. That's helpful. And then could you speak to the ability kind of mentioned in the Presidential Memorandum of sourcing a U.S. deal to build it, where you are with what actually you have in inventory that you can use, kind of how you'll work through the mechanics of that?

[Paul Miller:]

Yeah. It's Paul again. We're aware of the Presidential Memorandum and we understand the Secretary of Commerce is charged with implementing the provisions of the memorandum. We don't have the visibility today. We'll analyze the plan when it's released to determine any impact it may have on Keystone itself.

[Theodore Durbin:]

Okay. That's it from me. Thank you.

[David Moneta:]

Thanks, Ted.

[Operator:]

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

[Robert Catellier:]

Yes. Hi. I just have a couple of follow-ups on Keystone XL, and maybe you can provide a little bit more color on where you are with the shippers, specifically whether or not you anticipate a need for an open season. And in addition, how are you providing clarity to the shippers on the toll, while at the same time protecting returns when there is a little bit of uncertainty in terms of what the U.S. administration might want in terms of profit sharing?

[Paul Miller:]

Rob, it's Paul here. First of all, as far as where we're at with the shippers, again appreciate that a lot has occurred since November 2015. The shippers, they have a different price environment, they are operating in the different supply forecast. There's different competition out there. So the shippers are going through their own analysis. We are providing them with the detail we do have around Keystone XL as well as our commercial terms. And ultimately, we will look to amend the contracts we do have in place. To the extent that we have additional capacity available on Keystone XL, we would love to go to an open season, but at this point we don't have any plans at this point. In regard to some of the other matters that you spoke of, we're not aware of any additional terms that might be required for us to achieve the presidential permit. We currently are working through the regulatory process as we understand it, and we'll work with the administration to that end and we'll continue to work with the shippers and to the extent that something does occur, we'll provide some visibility at that point.

[Robert Catellier:]

Okay. And then on the Mainline. Karl, maybe you can give a little bit more color as to what the approach would be for the LDCs in how you position any new long-term fixed price agreement on the Mainline and how you would position that to be successful in the hearing?

[Karl Johannson:]

Yeah, sure. I think there's two real main benefits that I see to the system from doing a longer-term deal. Number one, the Eastern LDCs have been very clear and vocal. And part of the actual LDC settlement was us facilitating a change in how they procure natural gas. They have wanted very much to procure natural gas set closer to the market hub and not have to go back to the supply hubs to get it. They are our traditional long haul shippers so they have been decontracting, they have already been decontracted before we even did the settlement, they've decontracted almost 1 billion cubic feet a day since the LDC settlement went into place. And so they've sent a very strong message to the market that they're waiting to purchase at dawn, which is volume entering Canada that's facilitated through the LDC settlement. Our goal is to not let that pipeline capacity remain empty with our exit. Our goal is just to move gas and we believe that we can make a case if this is incremental movement as gas wouldn't happen and otherwise from this particular deal, and that equates to incremental revenue on the system, which helps everybody working on the system. The LDCs out East get more gas before dawn to compete. The other shippers on the Mainline get extra revenue to help shoulder the burden of the cost in the Mainline. So that's our basic argument and it's clearly an economic argument of where we're placing volumes that we believe the LDCs have exited, and they are – with no intention of going back and we will replace it with producer volume. So I'm quite certain that that economic argument will be quite compelling.

[Robert Catellier:]

Yeah. That's a fullsome answer. I'm just a little curious as to how you navigate the issue of term given there was so much pushback from the producers on the right that was a reasonable term expectation in the first place.

[Karl Johannson:]

You turn to something that – frankly, the terms of that we have been discussing for a very long time. Again, as I talked about earlier, the producers in the WSSB are not all that familiar and not all that comfortable taking longer-term contracts. I think the Mainline is basically on the year-to-year term. What we are talking with the producers – and again, I have to remind you that we have not come to an agreement. Well, we are talking to them as a 10-year term with various off-ramps that penalties are based, so to speak. The Mainline is – essentially everything else in the Mainline is running from year-to-year. So I think that the term that we got is actually quite compelling for a Mainline shipment.

[Robert Catellier:]

Okay. Thank you very much.

[David Moneta:]

Thanks, Rob.

[Operator:]

Thank you. The next question is from Faisel Khan from Citigroup. Please go ahead.

[Faisel H. Khan:]

Hi, thanks. It's Faisel from Citi. Just two questions, the first one is on the approval for the pipelines on the Columbia System, the WB XPress, Mountaineer XPress, Gulf Xpress, how did the lack of a quorum right now at the FERC affect the insurance date of these pipelines? And then I have a follow-up.

[Russell K. Girling:]

Well, right now, I think we are fine. We weren't expecting the decisions on those particular pipelines to come imminently anyways. I would have to say where we are, we're looking anxiously as I know everybody else in the industry is at the replacement, and to get a quorum back at FERC. And we're hoping that it'll be dealt with expeditiously. But right now, we don't consider that to be on the critical path and we got the permits we need that are on a critical pathway now, and that being the Leach XPress and the Rayne Xpress. But having said that, we are like most others in the industry watching anxiously to see how the process flow unfold to get the quorum back.

[Faisel H. Khan:]

Okay, got it. And then last question, on the CPPL transaction, were you able to get the 100% or do you not need the 100% to close the transaction?

[Donald R. Marchand:]

It's Don here. We reached the quorum we needed to get that over the finish line.

[Faisel H. Khan:]

Okay. Understood.

[Donald R. Marchand:]

Yeah.

[Russell K. Girling:]

Yeah.

[David Moneta:]

Great. Thanks, Faisel.

[Operator:]

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

[David Moneta:]

Great. Thanks very much. We very much appreciate your interest in TransCanada and your patience this afternoon. Again, I know our remarks were a little longer than normal, but hopefully you found the incremental information useful. We look forward to speaking to you again in the not too distant future. Thank you.

[Operator:]

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