David Moneta - TransCanada Corp. Russell K. Girling - TransCanada Corp. Donald R. Marchand - TransCanada Corp. Stanley G. Chapman - TransCanada Corp. Karl Johannson - TransCanada Corp. Paul Miller - TransCanada Corp..

Linda Ezergailis - TD Securities, Inc. Ben Pham - BMO Capital Markets (Canada) Jeremy Bryan Tonet - JPMorgan Securities LLC Robert Kwan - RBC Capital Markets Robert Catellier - CIBC Capital Markets Tom Abrams - Morgan Stanley & Co.

LLC Andrew Kuske - Credit Suisse Securities (Canada), Inc Robert Hope - Scotiabank Derek Walker - Bank of America Merrill Lynch Matthew Taylor - Tudor Pickering Holt & Co. Securities- Canada ULC Pat Kenny - National Bank Financial, Inc. Joe Gemino - Morningstar, Inc. (Research).

Good day, ladies and gentlemen. Welcome to the TransCanada Corporation 2018 Second Quarter Results Conference Call. I would now like to turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr. Moneta..

Thanks very much and good morning, everyone. I'd like to welcome you to TransCanada's 2018 second 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 our 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. A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com.

It can be found in the Investors section under the heading Events. Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Nicole Forest (00:01:16) following this call and she will be happy to address your questions.

In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue.

Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Duane and I would be pleased to discuss them with you following the call.

Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities Regulators and with the U.S. Securities Exchange Commission.

And, finally, 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. 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.

With that, I'll turn the call over to Russ..

Canadian, U.S., and Mexican natural gas pipelines, liquids pipelines, and energy. As we advance our CAD 28 billion near-term capital program, we expect to deliver additional growth in earnings and cash flow per share.

As a result, we expect to grow our common dividend at the upper end of 8% to 10% on an annual basis through 2020 and foresee an additional growth of 8% to 10% in 2021.

In addition, we have more than CAD 20 billion projects that are in the advanced stages of development and we expect numerous other growth opportunities to emanate from our extensive asset footprint. Success in advancing these and/or other initiatives could extend our growth outlook.

At the same time, we have maintained a strong financial position to ensure that we are well-positioned to prudently fund our ongoing capital programs. That concludes my prepared remarks and I'll turn it over to Don to provide more details on our second quarter financial results..

lower contributions from the U.S. Power and Eastern Power following the sale of generation assets in 2017; increased outage days and lower results from contracting activities at Bruce Power; and narrower spreads realized by natural gas storage.

These reduced results were partially offset by higher realized prices on increased generation volumes for Western Power. For all our businesses with U.S. dollar-denominated income, including U.S.

natural gas pipelines, Mexico natural gas pipelines, and parts of our liquids pipelines and energy businesses, Canadian dollar translated EBITDA was negatively impacted versus the second quarter of 2017 by a weaker U.S. dollar. This was largely offset by lower translated interest expense and U.S.

dollar-denominated debt and realized hedging gains reported in comparable interest income and other. Regarding our exposure to foreign exchange rates, our U.S. dollar-denominated assets are predominantly hedged with U.S. dollar-denominated debt and the associated interest expense.

We continue to actively manage the residual exposure on a rolling one-year forward basis.

Now turning to the other income statement items on slide 17, depreciation and amortization of CAD 570 million increased CAD 54 million versus second quarter 2017, largely because of new facilities entering service across our businesses and a higher depreciation rate on NGTL, partially offset by the sale of power generation assets in 2017 and a weaker U.S.

dollar. Interest expense of CAD 558 million was CAD 34 million higher year-over-year, following new debt issuances net of maturities and lower capitalized interest on liquids pipelines projects placed in service in 2017, partially offset by the repayment of Columbia acquisition bridge facilities in second quarter 2017 and the impact of a weaker U.S.

dollar in translating U.S. dollar-denominated interest. AFUDC decreased by CAD 8 million for the three months ended June 30, 2018, compared to the same period in 2017.

A decline in Canadian dollar-denominated AFUDC was principally due to the October 2017 decision not to proceed with the Energy East pipeline project and completion of the NGTL 2017 Expansion Program, while an increase in U.S.

dollar-denominated AFUDC was largely driven by additional investment in and higher rates on Columbia Gas and Columbia Gulf growth projects as well as continued investment in new Mexican pipelines.

Interest income and other included in comparable earnings increased by CAD 15 million in the second quarter versus 2017, primarily as a result of the net effect of higher interest income on an inter-affiliate loan receivable from Sur de Texas and realized hedging gains in 2018 on foreign exchange management compared to realized losses in 2017, partially offset by the foreign exchange impact on the translation of foreign currency denominated working capital balances and income related to the reimbursement of Coastal GasLink project costs recorded in 2017.

The interest income on the inter-affiliate loan is fully offset by interest expense included in Sur de Texas equity income within Mexico natural gas pipelines' EBITDA.

Income tax expense included in comparable earnings was CAD 146 million in the second quarter 2018 compared to CAD 198 million for the same period last year, primarily on account of reduced tax rates under U.S. Tax Reform and lower flow through income taxes on Canadian rate-regulated pipelines, partially offset by higher pre-tax comparable earnings.

Excluding Canadian rate-regulated pipelines, where income taxes are a flow through item and are thus quite variable, along with equity AFUDC income in U.S. and Mexico natural gas pipelines, we expect our 2018 full-year effective rate to be in the mid to high teens.

Net income attributable to non-controlling interests increased by CAD 21 million for the three months ended June 30, 2018, mostly due to higher earnings in TC PipeLines, LP. And, finally, preferred share dividends were comparable to second quarter 2017.

Now, moving to cash flow and distributable cash flow on slide 18, comparable funds generated from operations of approximately CAD 1.5 billion in the second quarter reflects an increase of CAD 92 million year-over-year, driven largely by higher comparable earnings as outlined and after allowing for the impact of power generation asset sales in second and fourth quarter 2017.

Previously, we provided two measures of comparable distributable cash flow, one factoring in all maintenance capital and another including only non-recoverable maintenance capital. Starting this quarter, we will provide a single measure reflecting only non-recoverable maintenance capital.

As Russ noted in his remarks, maintenance capital amounts where we have the opportunity to earn a return of and on such capital through tolls on our Canadian and U.S. rate-regulated pipelines or recover them in tolls on our liquids pipelines will no longer be deducted from distributable cash flow.

This represents approximately 85% of current maintenance capital expend. Going forward, three years of all estimated maintenance capital will now be reflected in our near-term capital projects table.

We believe that including only non-recoverable maintenance capital in the calculation of distributable cash flow conveys the best depiction of cash available for reinvestment or distribution to shareholders as our ability to recover rate-reregulated maintenance capital expenditures through current or future tolls is effectively the same as that of growth capital.

As a result, distributable cash flow in the quarter, as now defined, was approximately CAD 1.3 billion or CAD 1.46 per share compared to CAD 1.2 billion or CAD 1.36 per share in the second quarter of 2017, resulting in a coverage ratio of 2.1 times. We continue to expect to maintain strong DCF coverage through 2020. Now, turning to slide 19.

During the second quarter, we invested approximately CAD 2.6 billion in our capital program and successfully funded it through strong and growing internally generated cash flow, long-term debt issuance, and common equity from our dividend reinvestment plan and at-the-market program.

In the three months ended June 30, 2018, we issued US$2.5 billion of Senior Unsecured Notes comprised of US$1 billion of 10-year notes at a fixed rate of 4.25%, US$500 million of 20-year notes at a fixed rate of 4.75%, and US$1 billion of 30-year notes at a fixed rate of 4.875%.

In early July, we raised CAD 1 billion through a Canadian Medium Term Notes offering comprised of CAD 200 million of 10-year notes at a fixed rate of 3.39% and CAD 800 million of 30-year notes at a fixed rate of 4.182%.

Our dividend reinvestment plan or DRIP continues to provide incremental subordinated capital in support of our growth and credit metrics. In the second quarter, the participation rate amongst common shareholders was approximately 33%, representing CAD 208 million of dividend reinvestment.

Year-to-date, the participation rate has been approximately 36% resulting in CAD 442 million of common equity at a 2% discount.

In June of last year, we established an at-the-market or ATM program that authorized us to issue up to CAD 1 billion in common shares from time to time over a 25-month period at our discretion at the prevailing market price when sold in Canada or the United States.

In the second quarter, 8.1 million common shares were issued under the program at an average price of CAD 54.63 per share for gross proceeds of CAD 443 million, bringing year-to-date gross proceeds to CAD 772 million. Combined with ATM activity in late 2017, this served to effectively exhaust the existing authorization.

In June 2018, we replenished the ATM program capacity effective through July of 2019 which will allow us to issue up to an additional CAD 1 billion of common shares in treasury or its U.S. dollar equivalent. Use of the ATM will continue to be influenced by our spend profile, as well as the availability and relative cost of other funding sources.

The program is highly flexible with a fee structure that is attractive, even in comparison to DRIP. Some level of common share issuance through DRIP or ATM is viewed as a necessity now as we simultaneously prosecuted CAD 28 billion capital program and deleverage.

These should not, however, be viewed as permanent elements of our finance plan and we remain highly focused on share count and per share metrics. Going forward, we expect the recycling of capital through portfolio management to play an ongoing role in meeting our financing requirements.

To that end, as announced today, we have executed an agreement to sell our 62% interest in the Cartier power generation assets for approximately CAD 630 million. The proceeds will contribute to funding our capital program. The sale is expected to close in the fourth quarter this year and resulting in an estimated gain of CAD 130 million after tax.

Now turning to slide 20, this slide highlights our forecasted sources and uses of funds in 2018. Our capital requirements continue to be financed in a manner consistent with achieving targeted run rate credit metrics of a minimum 15% FFO to debt and maximum 5 times debt-to-EBITDA.

Starting in the left column, our dividend and non-controlling interests distributions of approximately CAD 2.8 billion, 2018 capital expenditures projected to be CAD 10 billion including maintenance capital, and long-term debt maturities of CAD 2.9 billion bring our total funding requirement for 2018 to approximately CAD 15.7 billion.

The middle column highlights aggregate sources of approximately CAD 13.5 billion, including forecast full year internally-generated cash flow of about CAD 6.4 billion in previously described funding year-to-date.

This leaves an additional CAD 2.2 billion balance of year requirement, which we expect to source through some combination of long-term debt, hybrid securities, ATM and possibly further asset sales. As we assess this year and beyond, we iterate that we do not foresee a need for discrete equity to complete our near-term CAD 28 billion capital program.

In summary, while our external financing needs are sizable, it remain imminently achievable in the context of multiple financing levers available in the clear, accretive and credit supportive use of proceeds. Now turning to slide 21. In closing, I offer the following comments.

Our solid across-the-board financial and operational results in the second quarter highlight our diversified low-risk business strategy and reflect the strong performance of both our blue-chip legacy portfolio along with the contribution of equally high quality assets from our ongoing capital program.

Today, we are advancing a CAD 28 billion suite of near-term projects 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.

We remain well-positioned to fund our near-term capital program through resilient and growing internally-generated cash flow and strong access to capital markets on compelling terms, supplemented further by capital recycling.

Our portfolio of critical energy infrastructure projects is poised to generate significant growth in high quality long life 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 and an additional 8% to 10% in 2021.

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

Thanks, Don. Just a reminder before I turn it over to the conference coordinator for your questions, those questions from the investment community, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue. With that, I'll turn it over 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. With respect to the FERC recent ruling, I know there is still a lot of uncertainties. But can you give us some sense of a potential timeline to get clarity on various aspects of that? And within that, do you expect industry and TransCanada to request any further rehearings or clarifications? Any context would be appreciated..

So, Linda, this is Stan. I'll start and I'll just point out at the beginning that FERC's Actions during July were actually directionally positive for us. They did a number of things.

Most importantly, while they clarified that their Revised Policy Statement that MLPs should not receive a tax allowance still holds, they noted that pipelines are not necessarily mandated to comply with that policy now. And, in fact, they left the door open for pipelines on a case-by-case basis to justify a tax allowance.

Procedurally, the mechanism remains the same which is pipelines are required to make these 501-G filings. The first round of filings will be made in October. The last round will be made in December. And I would expect that process is likely to continue into the first or maybe second quarter of 2019 until we get final clarity.

Most importantly, though, however, in the first option that you have which was to file a limited Section 4 rate case, FERC gave pipelines two different paths that they can go down. On one path, they clarified that if you are an MLP, you can comply with the Policy Statement and incorporate a zero income tax allowance.

And in doing such, you would get to eliminate your deferred tax balance. That's significant. It's significant because eliminating the deferred tax balance actually increases rate base and helps to offset partially or maybe in some cases totally the decline you'd otherwise see with the lower tax rates.

The other option would be to reduce your tax rates solely to reflect the 21% FERC tax rate and then argue in the next rate case why that particular pipeline is in a unique position and should be able to continue collecting a tax allowance contrary to the Commission's policy. So a lot more work to come.

I don't necessarily see us seeking any significant further clarifications. I think we have pretty good guidance right now. And I would say just bear with us as we make our first round of 501-G filings and we start engaging with our customers. And we'll probably engage with the customers here in advance of making those filings.

In some cases, we may be filing a limited Section 4. In other cases, we may just be filing the 501-G filings and saying that that's good enough. So, each pipe has a unique set of tax and we'll deal with them on a case-by-case basis..

Thank you. And then just as a follow-up to your U.S. natural gas pipelines operationally, your consolidated outlook for the company has improved versus prior disclosure. And one of the factors was improved earnings from your additional contract sales and lower expenses in your U.S. natural gas pipelines.

Can you comment on the duration of the additional contracts? And I'm assuming that the lower expenses would also translate into 2019 and beyond, but I'm also interested in understanding whether or not those contracts are shorter-term or longer-term..

Yeah. So, on the Columbia system, a lot of the increased earnings you're seeing is due to the new growth projects that are placed in service. And, obviously, those are long-term contracts that are going to be with us for a very long time.

On the ANR and the Great Lakes system, we've been very successful in doing short-term year-to-year sales to capture those basis differentials, whether it's basis differentials coming out of the Permian and trying to find a way to get that gas in Chicago, or whether it's basis differentials added at WCSB that's trying to migrate into the U.S.

While the contractual terms are basically quarter-to-quarter, month-to-month, year-to-year, particularly with respect to the Western Canadian Sedimentary Basin, we do see those volumes continuing to flow for a longer duration..

That's helpful context. Thank you..

Thanks, Linda..

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

Okay. Thanks. Good morning. I had a question on the Québec wind asset sale. And I looked if Innergex is providing some more specific multiples on the sale and they're suggesting 9 to 9.5 times EBITDA.

And my question really is how do you think about reconciling that with some recent transactions that we've seen in the low-double-digits and also to your own market multiple?.

It's Don here, Ben. Well, each asset is unique in terms of its contractual term and like an operational characteristic. So, it may not necessarily be apples-to-apples in the case of every single project. You need to drill down into that.

I would just characterize it as saying we are very pleased with the number in the proceeds and they will be fully cash tax sheltered, an important component of backfilling our funding plan here..

Maybe, Ben, I could just add to that. As you think about EBITDA multiples, it's one measure of value. Looking at your trailing 12 months is one way of calculating it, looking at your EBITDA multiple on a go-forward basis and then your certain assumptions around what you think the market is going to look like post the contracted life of the asset.

And we had different views of those kinds of things. The primary driver for us is can we surface value at a lower cost of capital than our other sources? And we've always said that we will choose our lowest cost of capital.

When we look at the implied cost of capital here that we were able to achieve in selling this asset, it's well below where the incremental sources are. So that's – fits for us in terms of adding value for our shareholders is how we come to those conclusions..

All right. Great. And then on the distributable cash flow revision, can you remind me, when you're sending your dividend expectations on the growth going forward, it was always on this revised distributable cash flow. Is that correct? And I know you guys looked at EPS as well, but I wanted to check in and clarify that with you..

Hey, Ben. It's Don here again. I would describe DCF as a data point for us, really nothing more than that. Historically, going back a couple decades, our dividend is largely based on payout ratios driven by EPS and cash flow, so generally 80% to 90% of accounting earnings which equates to about 40% area of cash flow.

Those are probably the more critical points that we look at. DCF, as I mentioned, is really just a data point..

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

Thanks, Ben..

Thank you. The next question is from Jeremy Tonet from JPMorgan. Please go ahead..

Good morning..

Good morning..

Just wanted to start off with – thanks – with Mexico here and just wanted to see what updated thoughts you had on the geography post the elections here, if anything has changed on that front as far as your appetite to expand there.

And then, I guess, as well with regards to funding options, clearly you look to the lower source of capital when looking to fund, but just wondering if this geography, these assets as far as could be sold, they were thought to be sold in the past, how that stacks up versus the ATM? If you can kind of share your thoughts on those dynamics, that would be helpful..

Well, Jeremy, it's Karl. Maybe I'll start with just talking about the overall environment in Mexico. There has been a new President-elected. To-date, the President, I think, have said all the right things, particularly with our energy and natural gas pipelines and electricity business.

So, we are still waiting to get our first meetings with all the new appointees and whatnot. So, we still have some familiarization to do with this new administration. But to-date, we're quite comfortable with what has been said and then the actions that we've seen so far.

I would point out that what we're doing is fundamentally important for the economy of Mexico and we would expect that the natural gas business would continue to progress and grow as it has been in the past.

So, it's early days right now but what we've seen so far doesn't concern us at all and it demonstrate to us that it's more or less business as usual in our segment of the market. And for the funding discussion, maybe I'll turn it over to Don here..

Yeah. Jeremy, it's Don. As we look at share count growth, we will look to portfolio management as a way of slowing that or removing it to the extent we can. When we look at the comparative cost of capital there, things we do factor in are strategic position and growth prospects of the assets, cash taxes and the like.

So, not every asset is equal in that sense. I would say that, as I noted in my remarks, portfolio management will continue to play an important role here in the funding plan. I won't laundry list for you everything that we would conceivably look at selling.

All I would say is that when we look at our suite of contracted assets across the entire portfolio. It really does dwarf two things. One, the list of assets we could have dropped down into the LP which, at this point, is still not considered a viable funding vehicle or the other box in our funding program.

So I'd just watch for us to continue to chip away at that without any real pre-announcements of this and look to what we've done with the solars and Cartier and continue to look at one-off asset sales here for the time being..

That's helpful. Thanks.

And then just picking up on TCP there, if it's deemed to not be a viable funding vehicle anymore, just when do you think you might have the information sufficient to make that determination? If you reach that determination, what actions do you think you might take at that point? You realize we don't want to get ahead of ourselves here, but would you like to kind of consolidate the entity in if it no longer serves the purpose you intended or this is strictly an economics decision and that's how TRP will address the situation?.

It's Don here again. I think the news that came out here a couple weeks ago was actually directionally positive for the LP. That said, it remains a work in progress to figure out and get some clarity on what it's really worth at the end of the day here as we work through – Stan outlined all the various processes related to FERC filings and the like.

I would say, at this time, it remains a non-viable funding vehicle. It's unclear if and when in the future that might be restored. So it's not definitive. In terms of potential buy-in, I would describe it as a possibility down the road. But until again we get clarity what ultimately it's worth, that's sometime down the road.

But I'd also say it's neither a certainty nor a necessity for us to buy it in. So while directionally positive with the FERC Actions here in July I would say we're still kind of monitoring this and are really no closer to a decision on it..

And maybe just to add to Don's comment is your question on whether it's an economic decision or whether other considerations be brought to the fore. Primarily for us, it is an economic consideration. I think we've said that before. To the extent it makes economic sense for TRP shareholders we would consider it.

To the extent that it doesn't, we wouldn't likely move down that path..

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

Thanks, Jeremy..

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

Good morning. If I can come back just to the EPS outlook that you gave for the second half of the year and you touched on some of the factors in terms of whether they're ongoing.

I was wondering if you can provide some color as well on things like Marketlink tolls, walk up rates, marketing outlook and as well just as related to what's going on at the FERC given you don't expect anything retroactive or anything immediate, how that might play into the outlook in future years?.

Rob, it is Paul here. I'll start on the Marketlink tolling and the marketing, et cetera. So, on Marketlink tolls we have a range of tolls for contractual tolling. They range from around CAD 2 to CAD 2.50. Our spot walk-up rate, if I recall, is probably in the CAD 3.25 range but we'll cycle back and correct if I'm wrong in that regard.

As far as outlook goes, in the second quarter, we saw a softening of the market a little bit for those walk-up tolls in the early part of the quarter. As far as the volumes towards the end of the quarter, they picked up. And then, going into third quarter, they dropped off again and they've been relatively flat here so far in the third quarter.

On the marketing side, kind of the same profile. We picked up some good value kind of midway through the second quarter and into the third – towards the end of the second quarter.

Going forward, we're able to capture some of that value and I would expect to see the marketing results to be probably upwards of CAD 0.02 higher in Q3, might be able to hold that into Q4.

So, taken together, I would anticipate our results for marketing and Marketlink to be slightly higher in the third quarter and into fourth quarter, with marketing contributing a bit more partially offset by some reduced volume on Marketlink..

And then, Robert, this is Stan. With respect to the FERC Actions, like I said earlier, we'll be making our 501-G filings in October, November and December for the respective pipelines, as required. And in terms of the impact on TRP, I guess I'll just leave you with this. Last time, we told you that it was basically immaterial to TRP.

The FERC Actions here are directionally helpful. So, just think about it as being even more immaterial to TRP at the end of the day..

Okay.

And, actually, just in your second half outlook, does that include the booking of Mainline incentives?.

Karl?.

No. Actually, as it stands right now, we are not booking incentives. We probably won't book them until we get some good feedback from the board on which way the board is going to go.

Now, I will say that although it hasn't taken the current consensus of the Mainline, I will say that we have got our early reading, evidence in on the Mainline case and it was very modest. There's really only one issue to be adjudicated.

So I'm a little bit more optimistic we will have the adjudication of our rates done before the end of the year than I was before. But no, we haven't included the Mainline incentives in the forward-looking view..

Yeah. Robert, it's Don here. It wouldn't be a material amount regardless..

Okay. And then just finishing on funding in the slide 20, I'm wondering, how much of the CAD 2.2 billion is senior debt versus the other alternatives? And when it comes to asset monetizations, Don, you talked about possibly further asset sales this year.

Are there any active processes ongoing right now?.

Yeah. In terms of the amount of senior debt, where we are in senior debt in 2018, we have CAD 2.9 billion in maturities and we've raised about CAD 4.3 billion. So we've got CAD 1.4 billion of incremental senior debt that we've taken care of this year. In terms of that CAD 2.2 billion, it depends.

But I'd say some in the – our equity equivalent requirement is probably like 50% of that, consistent with our capital structure, I think, 40% to 50% of that CAD 2.2 billion. In terms of asset sale processes, I won't comment on that.

I'd just say that don't take silence as inactivity and watch for down the line without any specific guidance to any specific quarter, for something similar to the solars and the Cartier processes to repeat themselves..

That's great. Thank you..

Thanks, Robert..

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

Hi.

I'd like to discuss Coastal GasLink and has there been a recent challenge on the permits for that project? And if so, do you expect it to have to undergo an NEB review? And what's your appetite for that and any impact on the timeline?.

Hey, Robert. It's Karl. Yes, there has been a challenge to jurisdiction that we believe right now have our permits under the B.C. And this is wholly-owned B.C project. So, we have B.C permits for it and there has been a challenge that it should be under NEB jurisdiction. I'm not going to talk about our strategy going into this.

But as you could imagine, we will be involved and we will be waiting on how the NEB views this. But I will say this that we're ready to go on this project. We believe we're working we believe and we are working on valid permits from the appropriate regulatory agency.

So, although we will be obviously an interested party in any NEB jurisdictional process, we consider that we have good and valid permits right now from the proper regulatory agency and we're ready to go..

And then, Karl, just a comment on timeline before you have, I guess, any resolution on jurisdiction?.

Well, you will have to wait. There has been a filing with the NEB and we haven't heard back from the NEB at all on this filing. So, I'm sure we'll hear back in the next 30 to 60 days on what the NEB plans to do, if anything, with this particular filing.

But, as I said, I don't think that – right now, as it stands, we believe we have a valid permit, so we will – the main thing we're waiting for right now is an FID by LNG Canada. And we expect that before the end of the year. So we'll probably get much more information on the validity of the jurisdiction case before then in any event.

But, as I said right now, we consider we have proper permits. I will also add that change in jurisdictions and whatnot between NEB and provincial has been done before. It's just – generally, in my experience, it has not been that disruptive. So, even if something does happen, we have done jurisdictional changes before.

And we have – we hasn't delayed or upended any type of projects we've done. So we'll follow this through to its natural conclusion. But, as I said, the main thing we're waiting for is the FID that we expect for the end of the year..

Okay. That's a helpful color. Maybe I'll follow up with you offline for the details. Just with the change in Ontario government, I'm wondering if there's any serious change to your operating outlook and in particular if you can comment on the Bruce refurbishment program..

Rob, it's Karl again. I don't think – the short answer is there is no change to our operating outlook. We produce – especially at Bruce we produce power at very reasonable rates. The Bruce nuclear business itself is very important to not only the local economy around Bruce, but it's important for the entire nuclear industry in Ontario.

And I would add that all parties in Ontario, just outside of election stuff, all parties in Ontario have expressed support for the nuclear energy and particularly support for what Bruce Power is doing. So, we're expecting business as usual at Bruce Power..

And that includes the MCR program?.

Yeah. The MCR program – we still have expectation that we will be submitting our Unit 6 refurbishment in October 1 or before that, by October 1, and getting a decision from the government before January. So, we're still on track to do that. We have everything.

We're progressing well and we will expect to be in there before or around October 1 in our submission for our Unit number 6..

Robert, just to add, I mean, to Karl's point, is that all parties in Ontario have been supportive of the nuclear refurbishment program from a whole bunch of different perspectives, the primary one being low cost emission, less energy, just support the economy.

But along with that is job creation in this stable, emission-less electricity that will – it'll transcend to a number of decades here. So, all parties have been supportive of that plan. And as you know, it's already underway at Darlington.

And this is a program that is managing coordination with what OPG is doing and we're doing at the same time to ensure reliability and stability of power to Ontario consumers. As you know, Bruce provides about 30-and-change-percent of the power in Ontario. It will for a long time yet to come.

So, as we've had these discussions over the past several months, said all parties are supportive of low cost emission-less energy that's good for both the economy and job creation..

That's great. Thank you..

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

Thanks. A lot of good questions here. I just had one on backlog. I'm thinking of backlog as an indicator.

So, when the Bruce Power thing is formally approved, does that enter backlog in stages every year or is it all the whole 10 years project comes in at once? How is that going to work? Then I also wanted to ask about Coastal GasLink, if that was FID-ed – the LNG facility was FID-ed on, say, December 1, when would Coastal GasLink enter your backlog? And, secondly, I guess, when will the actual spending occur?.

Tom, it's Don here. Bruce would be – there are six sequential decisions to be made, one for each reactor that needs to be refurb. So they will enter the near-term secured growth projects on that basis. So if Unit 6 does go ahead, the cost of that would move to the near-term, but only the cost for that one.

With respect to Coastal GasLink, if we do get an FID by the end of the year, the entire cost of that project would move to the near-term project backlog. So it is based on when we have clarity on any scanning processes or approvals that are required..

In terms of spending on Coastal GasLink, your question on when do we start spending, it's a four-year build process. Large amount of spending probably wouldn't occur till probably closer to 2020. And we're at the current time working through our financing options. Maybe, Don, you might want to comment on that..

Yeah. In terms of the financing of Coastal GasLink, what we would be looking at for this specific project would be introducing joint venture partners and also project financing this given the nature of the cash flows and the risks contained in that project.

So, what would happen there is we would essentially take – assuming like a 70% project financing debt component, we could shrink the equity contribution to about 30% and then split that in half or even less, which would comprise our equity contribution of that.

So, the intent on Coastal GasLink would be to pursue that and shrink the total cost to a fairly manageable number in terms of our actual equity contribution over that four-year timeframe..

Maybe the last thing that I would add to that is the estimate that we have out there currently of CAD 4.8 billion, as we said before, that's an old estimate. I mean if we do achieve FID in the fall, we will revise that estimate and, directionally, it will be a larger number than that.

So, I think, as you think about financing it using a larger number, that's probably in the neighborhood of 5% to 10%, something like that..

Okay. And then real quick question on Marketlink, if your marketing activities are using DRAs to capture some additional volumes..

Tom, it's Paul here. On Marketlink, we have capacity of about 660,000 barrels per day and we optimize our power and our cost around that capacity. It's really a combination of managing the kilowatts and using DRA where we have points of constrain. So, the long answer is yes..

Okay. Thank you..

Thanks, Tom..

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

Hey. Thank you. Good morning. I think the question is for Karl and it's just when you think about restoring capacity on the Mainline, what are the gating items for you? I mean, obviously, there's a volume issue.

But how do you think about the gating items and just regulatory path ahead?.

Hi, Andrew. It's Karl. Yeah. So, let me start with the regulatory path. There will be very little regulatory path ahead with capacity at Mainline. It's generally maintenance issue. So, most of the capacity can be restored by either refurbishing compression or by in-line inspections or digs or integrity of the pipeline.

These are things – rather than doing integrity pipeline inspections, we would reduce pressure, for example, and these are how we would manage capacity down during times when there's less volumes. And the way to get them back is just to do those digs and do that integrity work. So, there'll be a small regulatory component.

If we have to replace some facilities, for example, or something like that, there might be – regulatory will come into then. But for the most part, were having good success bringing the idle capacity back on with very little new equipment being needed. Really the gating item is – and we could bring it on quite quickly, in stages.

It doesn't come on a very large box. We can bring it on like CAD 100 million at a time as we progress this maintenance work. So, the real gating item I think is getting the customer support for spending the extra maintenance dollars. And I would point out that the maintenance is not that material dollars' wise.

We're talking hundreds of millions versus billions for a new-build type of deal. So, the real gating item is getting financial support and then the volumes are ready to commit for it going forward..

Okay. That's helpful. And then how do you think about – and maybe this is a question for really Russ or for Don – on just relative returns on capital employed, Canada versus the U.S.

in natural gas pipelines?.

I think as we've always said, the range of our returns on pipelines is in that gilt, 7% to 9% kind of range, lower in Canada as a result of the other construct that we have here and the rate-regulated model. And in the U.S., it's slightly higher than that.

And the combination of the two is where we come up with the sort of 7% to 8% kind of average return for those kind of businesses..

Yeah. It's Don here. And it is reflective of the modestly different risk profiles of them. In Canada here, obviously, it's flow-through of income taxes, no counterparty risk, no volumetric risk. There's a bit more of that in the U.S., which we will be compensated for in a higher return.

So, on a risk-adjusted basis, I think, we're comfortable with the investment profile that's there on both sides of the border..

And then, one final question, if I may.

And I know it's a bit of fluid, but is there any impact to your business from just the changes that have happened in carbon recently in Canada?.

Not sure what you're referring to specifically, Andrew..

I guess there's a few sort of iterations to it.

Have you seen or talked to customers that have any changes in their behavior because of carbon pricing effectively changing and the regime around carbon changing in Canada versus what was proposed a while ago or any direct impact to yourselves?.

I think there is no major impact. We are subjected in certain jurisdictions to carbon levies, in Alberta and Québec, for example, today. Those are incorporated into our tolls and passed on to our customers.

As you can see by the demand on our systems, demand remains strong for our systems irrespective of what I would call sort of slight increases in the cost of our operation due to those increased taxes. It's still fundamentally required in those jurisdictions that we're experiencing those levies..

Okay. Thank you..

Thanks, Andrew..

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

Hello. Good morning, everyone..

Hi, Rob..

I just want to circle back onto the funding plan. So, slide 20 gives us the 2018 funding plan. I believe in Q1 you had a 2018 to 2020 outlook.

I just want to get a sense if there has been any meaningful changes to the CAD 3.5 billion of kind of equity equivalent over this timeframe, I guess, after we adjust for the Cartier sale or if there's been any additional thinking there..

Yeah. It's Don here, Rob. I'd say I'd characterize it as no tectonic shift in that funding plan. There have been some tweaks.

So, moving left to right in terms of the uses, I would say CapEx is up probably in the neighborhood of CAD 1 billion as we look at some new projects we've introduced this past while, some additional expenses on projects like Napanee. We do have new methane rigs here in Alberta. So, it's probably CAD 1 billion increase there.

We've also seen the LP drop its distribution by 35%, which negates part of that. So, uses are up probably CAD 1 billion. In terms of what we've completed in terms of funding here, I think, we had 21.5 billion-ish as a number previously. Funds from ops remains robust.

We're not seeing a whole lot of movement there, maybe directionally a little bit better. And then, with all the funding in terms of term debt and asset sales, we've chipped away at that. On the far right-hand side, as you would have seen last quarter, I think, there's about an CAD 8.5 billion total need there.

I would say that with the financing we've done and the sale of Cartier, we're probably down CAD 1 billion, CAD 1 billion plus on that. The other component that is there of CAD 3.5 billion is probably down marginally as we look at, I guess, the equity component of the sale of Cartier and the gain on that.

So nothing has moved materially in that whole makeup. In terms of the CAD 3 billion, CAD 3.5 billion of other that's there, I wouldn't say it's dollar-for-dollar equity equivalent. What's categorized in there is potentially portfolio management, future ATM, recoveries from projects, future DRIP. That's to be determined.

So, a longwinded way of saying no fundamental shift in any of those categories, but just some of the moving parts that we're thinking about here..

All right. That's helpful. Moving over to Keystone XL, Russ, I believe in your comments, you did mention that pre-construction activities are accelerating through 2018.

Just want to get a sense of are you looking for specific approval to move the project forward? And does it remain – Nebraska review – that will largely be the gating factor before an FID potentially in early 2019?.

I think, as we said before, I mean the updates we've provided today on what we have called the major items, the approvals in Nebraska along with the right-of-ways and the issuance of BLM and Army Corps permits are on our watch list.

As well, we're looking at other legal proceedings that have been initiated, the one in Montana, for example, monitoring the outcomes of those, along with the ongoing work that we're doing on the commercial fronts. We said we're pretty much done there, but there's a lot of activity still yet to be done.

We would hope that all of that would sort of culminate in sufficient information to allow us to make a decision later in the year, early into next year. But we don't control, as you know, the timing of those processes. So we're being very cautious and careful about how we're spending our money.

We're spending it cautiously, but trying to maintain a schedule that allows us to build in 2019 and 2020. But we'll make decisions on a monthly basis as we go. As you know, we've been at this for almost a decade.

And we're just methodically going through each of these pieces and making sure that we dot our I's and cross our T's before we make any big steps..

All right. That's helpful. Thank you..

Don, do you want to add to that?.

Thanks, Rob..

Thank you. The next question is from Dennis Coleman from Bank of America Merrill Lynch. Please go ahead..

This is Derek Walker on for Dennis. Our questions have been answered. Thank you..

Thanks, Derek..

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

Hey, guys. Thanks for taking my question here. Just a question on the Northeast B.C. gas system. If Coastal GasLink goes ahead, looks like North Montney will be able to fill majority of Phase 1, but just wanted to get a sense of appetite to increase bidirectional capabilities maybe shipping some gas from Northwest Alberta.

Just trying to get a sense if there is a Phase 2 or other LNG projects and how you're viewing your system up there..

Hi, Matthew. It's Karl. Yeah. I guess maybe I'll just start with Coastal GasLink. We do expect it to ultimately have some interconnection with the NGTL. And I would expect some NGTL volumes to go through. Are they specifically designated to North Montney or not, it really depends on who the producer is and how they help people stream themselves.

But as Coastal GasLink interconnects with NGTL, it will be able to draw from the greater NGTL System which I think is a big benefit for these LNG projects to be able to get into the overall NGTL System. I would put out that there are some expectations on Coastal GasLink to be able to direct connect it from their own Northeast B.C.

gas supply as some of the partners have gas supply that is proximate to the pipeline. So, I would expect that we would see some direct connect. Obviously, we are working closely with them to see if we can do a deal to get that on NGTL's wallet but that may end up as direct connect. And so, it will be probably a mixture of both.

The facility – the two trains at the facility will probably be bringing approximately 2 Bcf a day. And it depends on how each individual partner ramps up their proprietary production as to how much kind of incremental goes into the market for acquisition, per se. You would expect this to have a normal curve on that.

I'm pretty certain most proponents are not building this facility to short of the net market, I'm expecting a lot of them use a majority of their own production. But that will probably be ramped up over time, so they'll probably lean on more of the market earlier than later.

If they do expand the system, you could expect an expansion will be probably another two trains which would be another 2 Bcf a day plus or minus. So, it gives you an idea. They have not made an FID around the first two trains, let alone the next two trains. So, I'd just point that out.

And there are still many other proponents of LNG that I think had some Northeast B.C. potential and then WCSB in general, NGTL, Northeast B.C. specifically can serve. So, I have no concerns with our capability to serve any LNG facility that comes along. So, we have a very big robust system.

As a matter of fact, I would expect most LNG facilities would be looking to NGTL because of the robustness of that system as a source of gas..

And then just on that Coastal GasLink, I understand it's a 48-inch pipe.

What's the expandability of that system?.

Well, I think we could bring it probably to the 5 Bcf a day through compression. Maybe that's stretching it a little bit. But certainly the first expansion we can get over 4 Bcf a day and I think approximately 5 Bcf with fully compressed..

Is that any looping of the pipe or....

No. That would be before new pipe goes in the ground. That would be just compression..

Okay. Thanks..

Thanks, Matthew..

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

Yeah. Hey, guys. Just on the Joliet open season, wondering if that was a one and done type of offer to shippers, or if you'll be going back to the drawing board, so to speak, and try to launch a round two sometime soon..

Yeah. It's Karl again. I wouldn't call it one and done. That offer was in response actually to producers asking for us to bring more products to them. And I personally think it was a great product to this day, I'll be honest. I haven't received any reasonable feedback as to why it was not fully subscribed.

But you can expect us to continue to be in the market for products, maybe that product again, but maybe there'll be different derivatives of that project. And I'm not too concerned anyways. The bottom line is we have a lot of gas now that's sitting in Empress. That's going to move down the Mainline.

So, if they don't buy it on a term basis on a structured product, they'll be buying it kind of on our yearly tariff product. So, I'm sure the gas is coming. So, I'm not concerned that we're not going to move the gas.

But we're still in the market looking for feedback for new products for people and we're not afraid to come back with a new product if we believe that it will be subscribed..

That's great. Thanks for that, Karl. And then, just maybe back on North Montney. I'm not sure how much you can comment on any feedback that's coming from shippers so far on the new tolling mechanism there.

But perhaps you can just provide a bit more color on how you see the new methodology shaking out and maybe an update on timing for finalizing the tolls there..

Yes, I can. Well, quite frankly, we were in discussions with all of our shippers in that area, not just North Montney, for a long time on kind of new tolling methodologies for the Northeast B.C. part of our system. So, these discussions haven't been new.

I guess the decision that we got from the NEB kind of hurried it up a bit, so to speak, specifically with North Montney. But what I can say right now is we are in discussions. We are actually far along in discussions for a new tolling method for North Montney and with the North Montney shippers.

I can't talk details with it just yet because they're still not finalized. But I can say that it's still going to have aspects of roll-in. It will be probably roll-in tariff with an adder to reflect the location of it. And that's kind of the road we're moving down right now. And that was the road, quite frankly, we're moving down in before this hearing.

I think the board kind of was just giving us a message that they wanted us to do this quicker through their discussion on the North Montney variance to application. So I don't have at my fingertips what the conclusion date is going to be, but I think you could expect this fall.

Sooner rather than later, you will see us come out with kind of a negotiated settlement, so to speak, for a proposal for an adjustment to the rates for that area and then to be brought to the NEB..

All right. Great. Thanks again, Karl..

Thanks, Patrick..

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

Thank you.

Can you provide any color as to any of the contract status of the Keystone XL and even the Keystone once the XL is placed into service?.

So, hi, Joe. It's Paul here. I'll start with new contracts on Keystone XL. We were able to secure about 500,000 barrels per day of 20-year commitments for Keystone XL in an open season earlier this year. Since that time, interest in the pipeline remains strong.

We continue to talk to producers and other interested parties and I would anticipate that that level of commitment would increase. When we bring Keystone XL into service, we will move probably about 200,000 barrels per day of contracts over from the existing pipeline on to XL.

So, when you combine the new contracts with those that we will transfer over with the amount of spot capacity where we are required to set aside for walk-up shippers, we will effectively be fully contracted on Keystone XL.

That does provide capacity on the existing Keystone System and we would look to contract that capacity up as well, serving markets in that Upper Midwest region..

Have you seen any interest in contracts on that existing – around the legacy system for the Upper Midwest region?.

We have. We are in discussions with various parties all the time across our network. And to the extent that they have a transportation requirement and we have a good solution for them, we'll certainly engage them in that conversation and ultimately secure long-term contracts from them. So, those conversations continue.

Some of the opportunities may be in the Upper Midwest. Some of them may be in markets further downstream to interconnecting pipes. But we are covering most of the marketplace, looking for opportunities to backfill the capacity on the legacy system..

Great. Thank you..

You're welcome..

Thanks, Joe..

Ladies and gentlemen, the call has now concluded. If there are any further questions, please contact TransCanada Investor Relations. I will now turn the call over to Mr. Moneta. Please go ahead, Mr. Moneta..

Thanks very much and thanks to all of you for participating today. We very much appreciate your interest in TransCanada and look forward to talking to you again soon. Thanks and bye for now..

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