David Moneta - TransCanada Corp. Russell K. Girling - TransCanada Corp. Donald R. Marchand - TransCanada Corp. Paul Miller - TransCanada Corp. Karl Johannson - TransCanada Corp. William C. Taylor - TransCanada Corp..

Linda Ezergailis - TD Securities, Inc. Robert Kwan - RBC Dominion Securities, Inc. Robert C. Hope - Scotia Capital Inc. Andrew Kuske - Credit Suisse Securities (Canada), Inc. Ben Pham - BMO Capital Markets (Canada) Theodore Durbin - Goldman Sachs & Co. Robert Catellier - CIBC World Markets, Inc. Faisel H. Khan - Citigroup Global Markets, Inc..

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..

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..

the $1.4 billion Leach XPress project and the $400 million Rayne XPress project. Both of those are expected to be completed by the end of this year. In total, we expect approximately $2.3 billion of Columbia's projects to enter service in 2017.

Looking forward, we expect our Columbia system to continue to generate organic growth opportunities as natural gas production in the Appalachian region grows from what its forecast today to be about 20 billion cubic feet a day to 30 billion cubic feet a day by the end of the decade.

With its highly connected network of receipt and delivery points and competitive path to markets, it's well positioned to capture its share of the infrastructure investment required to connect that growing supply to market. At the same time, we are working to identify opportunities to better integrate our U.S.

natural gas pipeline and storage assets to offer greater connectivity and enhanced services to all of our customers.

While that will take us sometime, it will include projects to move gas within the basin as well as westward onto ANR and onto Midwest markets, northward into Eastern Canada and then onto the Canadian Mainline, Iroquois and Portland pipelines for service into the U.S. Northeast, or even southward to the U.S.

Gulf Coast to service domestic markets, LNG markets, and potentially export to Mexico. Moving to the next slide, on this map, you can see our U.S. pipeline network is well positioned in key areas with access to multiple basins and demand centers. This includes pipelines held through our MLP, TC PipeLines, LP, which are highlighted in green.

Looking forward, the U.S. pipeline business could benefit from a number of other developments. First of all, the ANR settlement will result in higher contributions in 2017.

Of note, that settlement included $837 million of future modernization expenditures, and similar to Columbia's program, those costs are effectively included in the higher rates established under that settlement and therefore we'll earn a return of the non-capital related to that investment.

We also continue to look at additional opportunities across the broader U.S. natural gas pipeline portfolio. For example, our GTN system is well positioned to move incremental volumes as producers in the Western Canadian Sedimentary Basins continue to seek outlets for their growing production.

Great Lakes is well positioned to move additional volumes from the Western Canadian Sedimentary Basin to eastern markets as a result of its fair capacity and could be a direct beneficiary of any long-term load attraction agreement on the Canadian Mainline that could result in significant volumes of gas moving from Western Canada to Dawn.

Iroquois and our Portland Natural Gas Pipeline Systems provide relatively easy expansion opportunities into the New York and New England markets. With greenfield projects in this region facing a number of challenges on permitting, brownfield expansions on these systems could provide competitive paths to markets. Before I leave the U.S.

pipelines, I'd also like to reiterate that TC PipeLine remains the core element of our strategy, both from a strategic perspective as to where those pipelines are positioned, as well as from a financing perspective.

We continue to believe that it can play a meaningful role in our funding of our sizable near-term program, and Don will expand on this and other funding options in just a few minutes. Turning to Western Canada and our NGTL System, we believe that Western Canada shale plays are among the lowest cost sources of supply in North America.

Although development has been a little bit slower than in the Marcellus and Utica, it's evident that this resource base is very similar, primarily in the areas of the Montney, Duvernay, Deep Basin, Horn River and Liard areas. Each has proven to be quite prolific, with recoverable reserves in these regions having quadrupled over the past decade.

Connecting production from these emerging shale plays will require additional infrastructure and our NGTL System is ideally positioned to move that gas to market. Last year, the NGTL System transported 11.3 billion cubic feet a day, up from 11 billion cubic feet a day in 2015. In total, we moved about 75% of the gas production in Western Canada.

We've now contracted to build CAD 5.4 billion of new infrastructure through 2020 on the NGTL System to move that production to market. Approximately, CAD 1.6 billion is planned to be placed in service in 2017, improving the heat capacity of the system.

As new gas production is connected to NGTL, we will likely need to increase the main export delivery points in the province. NGTL also serves a large intra-Alberta market with a peak-day delivery of about 6.5 billion cubic feet a day. We expect the Alberta demand to continue to grow as the province transitions from coal-fired to gas-fired generation.

That will also require a new pipeline infrastructure and NGTL again is well positioned to provide that service. Turning to the Mainline, which continues to generate strong results, with incentives leading to rates of return on equity that are at the upper end of our allowed ranges.

Our multi-year LDC settlement, which went into effect in 2015, has certain elements extending into 2030, effectively creating long-term stability for that system. Today, that system moves between 2.5 billion cubic feet and 3 billion cubic feet a day from Western Canada to markets across Canada.

At the same time, in the Eastern Triangle, which is depicted by the brown triangle on the map, we are adding about CAD 300 million of expansion facilities to move growing amounts of U.S. shale gas.

That investment, along with the existing rate base in the Eastern region, will continue to earn a return on capital under a cost-of-service regulated model through 2030 under the LDC settlement.

At the same time, the western portion of the system, which we'll see its investment base continue to appreciate, will continue to play an important role, as I said, in linking Western Canadian gas supply to markets.

Although we haven't concluded a load attraction deal at this time, we're very encouraged by our discussions with Western Canadian producers over the past few weeks.

Regardless of how those discussions proceed, however, both the western portion of the Canadian Mainline and the Eastern Triangle are expected to continue to generate stable returns for our shareholders.

Turning to Mexico for a few moments, where we've seen significant growth over the last few years, today, we have four pipelines generating revenue under long-term take-or-pay contracts with the CFE. Three additional pipelines are under construction that will bring our total investment in Mexico to approximately $5 billion.

The $600-million Tula pipeline and the $550-million Villa de Reyes pipelines are both expected to end their service in early 2018. The $2.1-billion Sur de Texas offshore pipeline is anticipated to be in service in late 2018. We hold a 60% interest in that joint venture and we'll operate that pipeline.

Looking forward, ongoing Mexico energy sector reforms as well as the continued shift to natural gas from other fuels is expected to create additional opportunities. In addition, with now a system that effectively extends from the U.S.

border to the most populated regions of the country, we could see demand for incremental volumes and capacity additions to our existing strategically situated network.

Turning to liquids for a minute, the Keystone Pipeline has established itself as a premier crude oil transportation network by offering competitive tools, shorter transit times and reduced product degradation. In total, it has safely now delivered over 1.4 billion barrels of crude oil since entering service in 2010.

It is underpinned by long-haul take-or-pay contracts for 545,000 barrels per day, with an average remaining term of 15 years, providing visibility to an annual EBITDA of more than CAD 1 billion. Recent capital additions to the system have created optionality for us and to our shippers by improving access to more refining markets in the U.S.

Gulf Coast. Ultimately, this is expected to provide opportunities to move increased volumes, including U.S. shale oil volumes, on the southern portion of the line in the future. We're also advancing a number of intra-Alberta liquids pipeline projects, looking first at the Northern Courier Project.

This project is underpinned by a 25-year contract with Fort Hills partnership and is on track to be in service in 2017. Construction also continues on the Grand Rapids Project with completion expected later this year.

And today, we added a new project to our near-term portfolio, the White Spruce Pipeline, which will transport crude oil from a major oil sands plant in Northeast Alberta to the Grand Rapids Pipeline.

This CAD 200-million project is underpinned by a long-term contract and also provides additional long-term contracted volumes on the Grand Rapids system. We expect White Spruce to be in service in 2018.

Turning now to the Energy business, in the fourth quarter, we finalized the terms of a settlement with respect to the termination of our Alberta power purchase agreements. It included the transfer to the Alberta Balancing Pool a package of environmental credits held to offset the PPA emission costs.

That resulted in a non-cash charge related to the carrying value of those credits. The sale of our U.S. Northeast power business also continues to progress, and we expect those transactions to close in the first half of 2017. Once completed, we'll have substantially reduced our merchant power exposure.

The remaining 60 megawatts to 100 megawatts of power generation assets in our portfolio will largely be underpinned by long-term contracts with strong counterparties. Those remaining assets will generate approximately CAD 765 million of EBITDA, however, they did generate about CAD 765 million of EBITDA in 2016.

A number that we expect to grow to more than CAD 1 billion by 2020 as we complete the Napanee and advance work on the Bruce Power projects. Construction on Napanee continues and expect it to be in service by 2018. Work also continues on the asset management program at Bruce Power.

Those activities are being carried out in advance of the Major Component Replacement work that will begin on Unit 6 in approximately 2020. Looking forward, we will continue to assess opportunities in the renewable and gas power generation markets across our geographies as they become available.

Before I leave Energy, just a few additional comments on Bruce Power. We have been very pleased with its operating and financial performance over the past number of years. Bruce's average availability in 2016 was approximately 83%. In 2017, we expect that availability to increase to approximately 90%.

As part of the Ontario Government's Long-Term Energy Plan, the province has maintained their commitment to increase emission-free electricity generation. Bruce is very well positioned to supply this much needed power on a cost-competitive basis.

Major investments to extend the operating life of Bruce Power to 2064 will begin, as I said, with Unit 6 in 2020 and continue through 2033. This CAD 6.4 billion investment will see us invest approximately CAD 1.1 billion between now and the end of the decade, with the remainder being invested between 2020 and 2033.

So, in summary, today, we are advancing a CAD 23-billion near-term capital program that is expected to drive significant growth in EBITDA between now and the end of the decade. As you can see from this chart, comparable EBITDA is expected to grow from CAD 5.9 billion in 2015 to approximately CAD 9.3 billion in 2020.

That equates to a compound average growth rate of approximately 10%. Also of note, over 95% of that EBITDA will be derived from regulated or long-term contracted assets. Approximately 72% will come from Natural Gas Pipelines, 15% from Liquids Pipelines and 12% from Energy.

Based on the stability, our base business and our confidence in our growth plans, we expect to grow the dividend at an average annual rate at the upper end of an 8% to 10% range through 2020. This will be supported by expected earnings growth and growth in cash flow and strong distributable cash flow coverage ratios.

Success in advancing other growth initiatives over the forecast period could augment or extend our dividend growth outlook through 2020 and beyond. Finally, a few words on our CAD 45-billion portfolio of medium- to long-term projects. We expect to continue to develop these long-term options.

It includes our two West Coast LNG projects that are now fully permitted, the liquefaction facilities associated with those pipelines are also fully permitted and we're awaiting final investment decisions from those project sponsors.

As we have said, in the event that those projects do not proceed, we will be entitled to full recovery of our development cost, which today total approximately CAD 900 million. The portfolio also includes our two large scale liquids pipeline projects.

We continue to advance the Energy East project through the permitting process in Canada, and currently, we're awaiting direction from the newly appointed NEB panel that will oversee the regulatory review.

And finally, the Keystone XL Project, which began to advance again following the President of the United States' invitation to reapply for presidential permit. As a result of that invitation, as you know, on January 26, we filed a presidential permit application with the Department of State for the project.

And earlier today, we filed with the Nebraska Public Service Commission for the approval of the project route through Nebraska. Given the passage of time since November 2015, we are also updating our commercial arrangements with our shippers.

While some of the shippers may increase or decrease their volume commitments, we do expect to retain sufficient commercial support to underpin the project. We continue to believe that the U.S. Gulf Coast is the largest and most attractive market for growing volumes of Canadian heavy oil.

We also believe that the Keystone XL system is the safest, most efficient and most environmentally sound way to move that crude oil from Western Canada to the Gulf Coast. This project will enhance U.S. energy security, it will create significant employment for many U.S. citizens and it will generate significant and much needed tax revenues.

This project very much remains in the national interest of both Canada and the United States. That concludes my remarks. And I will turn it over to Don Marchand to provide more details on our fourth quarter and our longer-term financial outlook. Don, over to you..

Tula, Villa de Reyes and Sur de Texas. Next, Canadian Natural Gas pipelines add approximately CAD 200 million of incremental EBITDA as a result of the significant expansion program on the NGTL System, partially offset by the impact of depreciation of the investment basis of both NGTL and the Canadian Mainline.

In Liquids Pipelines, EBITDA is expected to grow by approximately CAD 300 million as we complete Northern Courier, Grand Rapids and White Spruce.

And finally, Energy EBITDA is also expected to grow by approximately CAD 300 million, due to the addition of Napanee and a higher contribution from Bruce Power, largely as a result of increases in the price received for power under the Life Extension Agreement.

So in total, we see EBITDA growing by approximately CAD 2.7 billion between now and 2020, bringing the total to approximately CAD 9.3 billion. That represents an annual growth rate of approximately 10% between 2015 and 2020.

To the extent we capture additional investment opportunities or identify revenue enhancements or operating efficiencies from our existing base businesses, that growth rate could be augmented over the forecast period. So turning now to slide 34, well this slide is quite busy.

The message is important as it highlights the long life nature and resiliency of our EBITDA and cash flow streams. When I introduced it at our Investor Day in November 15, in homage to my roots, I believe I affectionately referred to it as a Saskatchewan earnings cliff as flat as the eye can see.

Essentially, it illustrates that if we complete our CAD 23 billion of near-term capital program and do nothing else that spend maintenance capital through 2025, we would generate approximately CAD 8.4 billion of EBITDA in 2025 from regulated or long-term contracted assets.

Another CAD 400 million, which is shown in the other variable loan on the top of the chart that are green, it will come from our remaining merchant energy business in Alberta and market facing assets such as the southern portion of Keystone and certain U.S. Natural Gas Pipelines that are subject to re-contracting risk over this timeframe.

That said, as highlighted by Russ, we expect to continue to grow the business by capturing additional high quality, low risk investment opportunities over the forecast period and that is conceptually reflected in the purple wedge.

It could include further expansions of our NGTL or Columbia Systems, adding compression laterals in new projects in Mexico, additional regional Liquids PipeLines or contracted power plants along with one or more of our CAD 45 billion of medium to longer term projects.

By investing our discretionary cash flow after dividends and our debt capacity within the parameters of A-grade credit metrics, we are positioned to continue to grow well beyond 2020.

If we can't find the track of opportunities in our core businesses and within our risk tolerances, we will look to accelerate the return of capital to shareholders either through increased dividends or by proportionately shrinking the balance sheet in line with A-grade credit metrics. Turning now to slide 35.

This slide provides our outlook for distributable cash flow coverage ratios and maintenance capital through 2020.

As outlined in the chart on the left, given the forecasted growth and comparable EBITDA and cash flow, we expect distributable cash flow coverage ratios to remain robust and supportive of an expected annual dividend growth rate at the upper end of an 8% to 10% through 2020.

While our DCF coverage ratio is expected to drop to approximately 1.6 times in 2017, the decline is largely due to a temporary increase in maintenance capital as highlighted in the chart on the right.

Overall, we see normalized maintenance capital at approximately CAD 1.1 billion per year, which equates to 1.5% of our gross profit, plant property and equipment. However, we expect to spend an elevated CAD 1.5 billion on maintenance in 2017, largely as a result of the work being done on NGTL and ANR.

Recall that under ANR's recent rate settlement, we will invest $837 million over the 2016 to 2018 period to enhance the efficiency and reliability of the system with the full amount reflected in higher rates. This is essentially growth capital that happens to be defined as maintenance under GAAP.

Approximately $350 million or CAD 450 million of that amount is forecast to be spent in 2017 as depicted in the light blue colored box. In addition, we see maintenance on our Canadian regulated systems running about CAD 100 million higher than normal in 2017 as a result of ongoing work on NGTL, which is included in the dark blue colored box.

Again, any spend on NGTL or the Canadian Mainline is also reflected in their respective rate bases and net income.

So while our coverage ratio declines this year, it returns to approximately 2.0 times by 2020 as maintenance capital returns to more levels and cash flow growth accelerates as CAD 23 billion of commercially secured projects enter service. So in closing, I would offer the following comments.

Our diverse portfolio of high quality long life assets generated very strong comparable results in 2016. The acquisition of Columbia, as well as certain other initiatives over the past year, represent truly transformational events for TransCanada.

Today, we are advancing an industry-leading CAD 23 billion near-term capital program and have five distinct platforms for future growth in Canadian, U.S. and Mexico natural gas pipelines, liquids pipelines and energy. Our overall financial position remains strong supported by our A-grade credit ratings.

We remain well positioned to fund their near-term capital program through resilient and growing internally generated cash flow and strong access to capital markets on compelling terms.

Our industry leading suite of critical energy infrastructure projects is expected to generate significant growth and high quality earnings and cash flow for our shareholders. That is expected to support annual dividend growth at the upper end of an 8% to 10% range through 2020.

Success in adding to our growth portfolio in the coming years could augment or extend the company's dividend growth outlook through 2020 and beyond. That's the end of my prepared remarks, I'll now turn the call back over to David for Q&A..

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..

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

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?.

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..

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?.

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..

Okay. Thanks. Will jump back in the queue..

Okay. Thanks, Linda..

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

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%?.

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..

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..

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..

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

Thanks Robert..

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

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?.

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..

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?.

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..

Thank you..

Thanks, Rob..

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

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?.

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..

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?.

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..

. Okay. That's great. Thank you..

Thanks, Andrew..

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

Good afternoon. Just on that last comment about moving gas potentially into the Northeast markets (01:14:27) potential brownfield expansions. Is there any regulatory issue there with the buyer of that if you were to move gas during their contract..

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

Just to some of the electricity distribution companies?.

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..

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?.

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..

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..

Okay. That's helpful. Thanks everybody..

Thanks, Ben..

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

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?.

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..

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..

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?.

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..

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

Thanks, Ted..

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

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?.

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..

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?.

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..

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..

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..

Okay. Thank you very much..

Thanks, Rob..

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

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..

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..

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?.

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

Okay. Understood..

Yeah..

Yeah..

Great. Thanks, Faisel..

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

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