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

Thanks very much and good afternoon everyone. I'd like to welcome you to TransCanada's 2018 fourth quarter conference call.

With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Tracy Robinson, President of our Canadian Natural Gas Pipelines Business; Stan Chapman, President, U.S.

Natural Gas Pipelines; Francois Poirier, Executive Vice President, Corporate Development and Strategy, and President of our Mexican and Energy businesses; Paul Miller, President of Liquids Pipelines; and Glenn Menuz, Vice President and Controller.

Tracy and Francois have joined us for the first time in their expanded roles, following Karl Johannson's decision to retire. Both have been with TransCanada for a number of years in senior capacities. Russ and Don will begin today with some opening comments and our financial results and certain other company developments.

A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com. It can be found in the Investors section under the heading Events. Following their prepared remarks, we will take questions from the investment community.

If you are a member of the media, please contact Grady Semmens following this call and he would be happy to address your questions. In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please re-enter the queue.

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

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

And finally during the presentation we'll refer to measures such as comparable earnings, comparable earnings per share, comparable earnings before interest, taxes, depreciation and amortization or comparable EBITDA, comparable funds generated from operations, and comparable distributable cash flow.

These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance liquidity and its ability to generate funds to finance its operations.

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

Canadian, U.S. and Mexico, Natural Gas Pipelines; liquids pipelines; and energy. And just as we have done since 2000 as we advance our $36 billion secured capital program, we expect to deliver continuous growth in earnings, cash flow and dividends per share.

In addition we have more than $20 billion of projects that are in advanced stages of development and we expect numerous other growth opportunities to emanate from our extensive critical asset footprint.

We have a history of prudently funding our capital programs and we are on track to deliver -- to continue to delever our balance sheet post the 2016 acquisition of Columbia and achieve our targeted credit metrics.

That concludes my prepared remarks and I'll turn the call over to Don, who'll provide you with more details on the fourth quarter financial results and our 2019 outlook.

Don?.

Thanks Russ and good afternoon everyone. As outlined in our quarterly results issued earlier today, net income, attributable common shares is $1.1 billion or $1.19 per share in the fourth quarter of 2018 compared to $861 million or $0.98 per share for the same period in 2017.

Fourth quarter results included $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities; $115 million deferred income tax recovery from an MLP regulatory liability write-off resulting from our 2018 FERC actions; a $52 million recovery of deferred income taxes as a result of finalizing the impact of the U.S.

tax reform; a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets; and $25 million of after-tax income realized on Bison contract terminations. These positives were partially offset by $140 million after-tax impairment charge for Bison and a $15 million after-tax goodwill impairment charge for Tuscarora.

The amounts for Bison and Tuscarora which are held by TC PipeLines LP reflect our proportionate share of these impairments net of non-controlling interests. Lastly fourth quarter results included an after-tax net loss of $7 million related to the wind down of our U.S. Northeast power marketing contracts.

Fourth quarter 2017 results also include several specific items as outlined on this slide and discussed in the fourth quarter 2018 financial highlights release. All of these specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings.

Excluding specific items comparable earnings of $946 million or $1.03 per share in fourth quarter 2018 were $227 million or $0.21 per share higher year-over-year. This equates to a 26% increase on a per share basis after giving effect to the dilutive impact to common shares issued under our dividend reinvestment plan and after-market program.

These along with other funding activities do however have us on track to return to long-term targeted leverage metrics following the 2016 Columbia acquisition and continuing record capital program. Our positive results reflect broad operational strength and solid cash generation particularly in Canadian and U.S.

natural gas pipelines along with liquids pipelines. Turning to our business segment results on slide 20. Beginning this quarter, our financial disclosure will include enhanced information around comparable EBITDA and its key drivers period-over-period.

In the fourth quarter, comparable EBITDA from our five operating segments was approximately $2.5 billion, a $550 million or 29% increase from 2017. Canadian Natural Gas Pipelines' comparable EBITDA of $818 million was $249 million higher than for the same period last year.

The increase is primarily due to the recovery of higher depreciation as a result of increased rates approved in both the NGTL 2018-2019 settlement and the Mainline NEB 2018 decision as well as higher flow-through taxes and incentive earnings.

As a result of the timing of the NEB 2018 decision, the full year impact of higher depreciation flow-through taxes and incentive earnings on the Mainline was reflected in the fourth quarter.

The decision approved all elements of our application, including our cost and volume forecast, higher depreciation rate and continued pricing discretion with the exception of treatment of the long-term adjustment account or LTAA balance, which is now to be amortized over 2018 to 2020.

I would note that for Canadian Natural Gas Pipelines changes in depreciation and financial charges and income taxes impact comparable EBITDA, but do not have a significant effect on net income as they are almost entirely recovered in revenues on a flow-through basis.

Net income for the Canadian Mainline increased $11 million year-over-year primarily due to higher incentive earnings recorded in the period. Net income for the NGTL system increased $18 million compared to fourth quarter 2017, as a result of a higher average investment base continued system expansions and increased OM&A incentive earnings. The U.S.

Natural Gas Pipelines comparable EBITDA of US$613 million or CAD 812 million in the quarter, increased by US$138 million or CAD 208 million compared to the same period in 2017 mainly due to increased contributions from Columbia Gulf projects placed in-service, additional contract sales on ANR and Great Lakes and increased earnings from the amortization of net regulatory liabilities recognized following the U.S.

Tax Reform partially offset by a reduction in certain rates on Columbia Gas as a result of U.S. Tax Reform.

Mexico Natural Gas Pipeline's comparable EBITDA of US$115 million or CAD 152 million was US$24 million or CAD 36 million above fourth quarter 2017 as a result of changes in timing of revenue recognition equity earnings from our investment in the Sur de Texas pipeline which records AFUDC during construction, net of interest on an interaffiliate loan from TransCanada, along with incremental earnings McRae tariff increase.

The interest expense on the Sur de Texas interaffiliate loan is fully offset in interest income and other in the corporate segment.

Liquids pipelines' comparable EBITDA rose by $137 million to $538 million in fourth quarter 2018, driven by increased volumes on the Keystone pipeline system, a higher contribution from liquids marketing activities due to improved volumes and margins, incremental earnings from Intra-Alberta pipelines, which began operations in the second half of 2017 and lower business development costs as a result of capitalized and Keystone XL expenditures in 2018.

Energy comparable EBITDA decreased by $47 million year-over-year to $167 million due to lower earnings from Bruce Power, driven by reduced volumes from higher outage days, decreased Western and Eastern power results due to the sales of Cartier Wind in fourth quarter 2018 and Ontario Solar Assets in fourth quarter 2017 and a lower contribution from Natural Gas Storage, primarily due to pipeline constraints in Alberta limiting our ability to access the storage facilities, causing narrower realized price spreads.

This was partially offset by higher Western power realized margins on improved generating volumes. For all our businesses with U.S. dollar denominated income including U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines, and parts of liquids pipelines and energy fourth quarter 2018 Canadian dollar translated EBITDA benefited from a stronger U.S.

dollar compared to the same period in 2017. This positive foreign exchange impact at the business unit level was largely offset by higher translated interest expense on U.S.

dollar denominated debt and realized hedging losses on derivatives used to manage our net exposure to foreign exchange rate flow fluctuations reported in comparable interest income and other. As a reminder of our approach to managing foreign exchange exposure, our U.S. dollar denominated revenue streams are partially hedged by interests on U.S.

dollar denominated debt. We then actively manage the residual exposure on a rolling one-year forward basis. Now turning to the other income statement items on slide 21.

Depreciation and amortization of $681 million increased $165 million versus fourth quarter 2017, largely due to the increased depreciation rates on the Mainline and NGTL with amounts fully recovered as reflected in the increase in EBITDA described earlier, as well as new facilities entering service across our businesses.

Interest expense included in comparable earnings of $603 million for fourth quarter 2018 was $62 million higher year-over-year following net debt – new debt issuances net of maturities, higher levels of short-term borrowing, and increased translated U.S. dollar denominated interest due to a stronger U.S.

dollar, partially offset by higher capitalized interest, primarily due to ongoing construction of Napanee and the recommencement of capitalization of Keystone XL development costs in 2018.

AFUDC increased $21 million for the three months ended December 31, 2018 compared to the same period in 2017, due to higher capital expenditures on NGTL, continued investment in Mexico projects, and additional investment in and higher AFUDC rates on Columbia growth projects.

Comparable interest income and other decreased by $45 million in the fourth quarter versus 2017, primarily as a result of realized hedging losses on foreign exchange management in 2018 compared to realized gains in 2017, partially offset by higher interest income related to the inter affiliate loan receivable from the Sur de Texas joint venture offsetting the corresponding interest expense recorded in comparable EBITDA.

Even though they fully offset on consolidation, GAAP requires that we report the interest income and expense elements of this loan separately in the financial statements. Income tax expense included in comparable earnings was $268 million in fourth quarter 2018 compared to $234 million for the same period last year.

A $34 million increase was mainly on account of higher comparable earnings before income taxes and increased flow-through income taxes on Canadian rate regulated pipelines with such amounts fully recovered as reflected in the increase in EBITDA discussed previously partially offset by a reduced tax rates as a result of the U.S. Tax Reform.

Operable net income attributable to non-controlling interest of $86 million in the fourth quarter increased by $37 million relative to the same period last year, mostly due to higher comparable earnings in TC PipeLines LP. And finally preferred share dividends were comparable to fourth quarter 2017.

Now moving to cash flow and distributable cash flow on slide 22.

Comparable funds generated from operations of approximately $1.9 billion in the fourth quarter reflects an increase of $431 million year-over-year driven primarily by higher comparable earnings recovery of greater depreciation for NGTL and the full year impact of recovering increased depreciation on the Mainline.

Comparable distributable cash flow reflecting only non-recoverable maintenance capital expenditures was approximately $1.7 billion in the quarter or $1.89 per share compared to $1.3 billion or $1.45 per share in the fourth quarter of 2017, resulting in a coverage ratio of 2.7 times.

As highlighted previously, 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 recovery rate regulated and liquids maintenance capital expenditures through current or future tolls effectively nears that of growth capital.

Now, turning to Slide 23, during the fourth quarter, we invested approximately $3.4 billion in our capital program and successfully funded it through strong and growing internally-generated cash flow along with several diverse financing waivers.

In October we raised $1.4 billion through our senior unsecured notes offering comprised of $1 billion of 30-year notes at a fixed rate of 5.1% and $400 million of 10-year notes at a fixed rate of 4.25%.

Also in October, we closed the sale of the Cartier Wind power generation assets for approximately CAD630 million resulting in a gain of CAD143 million after tax recorded in the fourth quarter.

In November, the five parties to LNG Canada reimbursed us for their share of pre-FID development costs associated with the Coastal GasLink project totaling CAD470 million. Recently in January, all five parties elected to make cash payments throughout the CGL construction period with respect to carry charges on costs incurred.

In December, we entered into an agreement to sell our Coolidge Generating Station for approximately $465 million or CAD620 million subject to timing of the close and related adjustments. The sale will result in an estimated CAD50 million after-tax gain to be recognized upon closing of the transaction which is expected to occur in mid-2019.

Our dividend reinvestment plan or DRIP continues to provide incremental subordinated capital in support of our growth and credit metrics. In the fourth quarter, the participation rate amongst common shareholders was approximately 34%, representing CAD215 million of dividend reinvestment.

For full year 2018, the participation rate was approximately 35%, resulting in CAD870 million of common equity at a 2% discount.

Funding activity not just from the fourth quarter, but throughout 2018 continues to highlight the depth and diversity of the financial options available to us allowing us to prudently fund our capital program and achieve targeted credit metrics.

Now, turning to Slide 24, this graphic highlights our forecasted sources and uses of funds from 2019 through 2021.

Starting in the left column, the total funding requirement over the next three years is projected to be CAD29 billion comprised of dividend and non-controlling interest distributions of approximately CAD10 billion and capital expenditures of approximately CAD19 billion including maintenance capital.

The increase relative to Investor Day largely reflects the announced Louisiana XPress project as well as slight capital increases and modest project development costs. Also as a reminder, we are pursuing joint venture partners and asset level financing towards funding the CAD6.2 billion Coastal GasLink project.

The expenditure will be spread over approximately four years with a bulk of the spend in 2020 and 2021. For purposes of our funding program outlook through 2021 and consistent with what we conveyed at Investor Day in November, we assume we maintain a 25% interest in Coastal GasLink, which is reflected in our capital requirements.

The second column highlights aggregate sources including approximately $21 billion of internally-generated cash flow approximately $500 million of proceeds from our dividend reinvestment plan for the January 2019, dividend payment and the dividend declared today to be paid at the end of April, as well as approximately $620 million of proceeds from the announced sale of Coolidge Generating Station expected to close in mid-2019.

That leaves the capital markets requirement of approximately $6.9 billion in the far right column. We expect to issue approximately $3 billion of incremental debt through 2021 within the constraints of our targeted credit metrics of debt-to-EBITDA in the high 4s range and minimum FFO-to-debt of 15%.

Additionally we expect to issue $1.5 billion of hybrids maintaining these securities along with preferred shares at about 15% of our capital structure.

The remaining $2.4 billion as illustrated by the purple box will be comprised of activities such as incremental DRIP proceeds beyond the dividend most recently declared and portfolio management activities.

DRIP remains a quarter-to-quarter decision, influenced by financial performance against targeted metrics, along with the cadence of getting growth projects into service and the timing of asset sales.

With the deal for Coolidge now signed, we still have additional assets that generate approximately $500 million of annual contracted EBITDA that have been identified as potential viable portfolio management candidates. Applying a reasonable multiple the associated proceeds would notably exceed our residual funding requirement.

As in the past, while we will not preannounce targeted asset sales you should not take silences in activity as illustrated with our most recently announced transactions for Coolidge Cartier Wind and Ontario solar.

In summary while our external funding needs remain sizable they are eminently achievable in the context of the multiple financing levers available and are clear accretive and credit support of these proceeds. Everything is evaluated on a per-share basis and further share account increases will be assessed against additional portfolio management.

We reiterate that we do not foresee a need for discrete equity to complete our secured $36 billion capital program. And ultimately our goal is to revert to our historical self-funding model. Now turning to slide 25. Next I'd like to spend a moment on our 2019 comparable earnings outlook.

Additional information is contained in our 2018 annual management's discussion and analysis which is being filed on SEDAR today and available on our website. Canadian Natural Gas Pipelines earnings in 2019 should be higher than 2018 mainly due to the continued growth on the -- in the NGTL's systems investment base.

We expect earnings in the Mainline to be slightly lower due to decreased incentive earnings. The NEB 2018 decision to accelerate the amortization of the LTAA over the 2018 to 2020 period effectively reduces tolls revenues and income taxes in those years, but has no significant impact on net income. U.S.

Natural Gas Pipelines earnings are expected to be higher in 2019 than in 2018 due to among other factors increased revenues following the completion of expansion projects on Columbia Gas and Columbia Gulf in 2018 and 2019.

In Mexico Natural Gas Pipelines, we expect 2019 earnings to be higher year-over-year primarily due to the incremental contribution from the Sur de Texas pipeline which is projected to be in service in early second quarter.

In Liquids our 2019 earnings are expected to be similar to 2018 primarily as a result of significant take-or-pay contracts and continued high demand for capacity on our assets.

Our 2019 comparable earnings for the Energy segment are expected to be higher than 2018, primarily due to an increased contribution from Bruce Power, largely driven by an increased contract price to reflect the capital to be invested in the Unit six MCR and AM programs.

The average Bruce plant availability percentage in 2019 is projected to be in the high 80s range comparable to 2018. Incremental earnings and the completion of Napanee are also expected to drive higher energy results, partially offset by the sale of our interest in the Cartier Wind facilities in 2018 and the anticipated sale of Coolidge in mid-2019.

Comparable earnings per share in 2019 will also be impacted by the dilutive impact of common shares issued in 2018 under our DRIP and ATM program, and expected to reap issuance in 2019 along with higher interest expense as a result of debt financings to help fund our capital program and lower capitalized interest on projects placed in-service.

For our effective income tax rate, excluding Canadian rate regulated pipelines, where income taxes are a flow-through item nevertheless quite variable, along with equity AFUDC income in U.S. and Mexico Natural Gas Pipelines, we expect our full year 2019 effective rate to be in the mid to high teens.

Finally, as part of 2019 outlook, I would like to note that we have very limited interest rate foreign exchange or commodity price variability inherent in our diversified portfolio. In summary, comparable earnings in 2019 on a per-share basis are expected to be higher than 2018.

In terms of capital spending, our plan is to invest approximately $8 billion in 2019 on growth projects, maintenance capital and contributions to equity investments.

The majority of the anticipated 2019 capital program is attributable to expenditures on Coastal GasLink, NGTL Columbia Gas modernization 2 and the Bruce Power life extension program along with normal course maintenance capital expenditures of approximately $1.7 billion, of which approximately 85% is recoverable.

The 2019 capital program estimate includes $1 billion for the Coastal GasLink project, reflecting 100% of the capital spend. As previously messaged, we are seeking joint venture partners for up to 75% of the project. Lastly turning to slide 26. In closing, I offer the following comments.

Our solid across-the-board financial and operational results in the fourth 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 $36 billion suite of secured 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 secured capital program through resilient and growing internally-generated cash flow and strong access to capital markets on compelling terms, supplemented further by capital recycling. We will continue to make all funding decisions based on per share metrics.

Our portfolio of critical energy infrastructure is poised to generate significant growth and high-quality long life earnings and cash flow for our shareholders. That is expected to support annual dividend growth of 8% to 10% through 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'll now turn the call back over to David for the Q&A..

Great. Thanks, Don. Just a reminder, before I turn it over to the conference coordinator for questions from the investment community, we do ask that you limit yourself to two questions. If you have any additional questions, please reenter the queue. Now, with that, I'll turn it over to the coordinator..

[Operator Instructions] First question is from Linda Ezergailis from TD Securities. Please go ahead..

Thank you. Congratulations on a strong quarter..

Thanks, Linda..

This is a question with respect to your Canadian Natural Gas Pipelines.

Can you give us a sense now of where the pinch points are in the path to market? And how might the next round of debottlenecking and potential expansions unfold?.

Hi, Linda. Good afternoon. We have as you know a very strong supply base in the WCSB. In fact we have -- our issue was not supplier issuance market. And we're working as hard as we can to address the egress issues we have in 2018 about 900 million cubic feet a day more moving to the system than they did in 2017.

And we have -- should Russ talk about $8.6 billion going into incremental egress off the NGTL system over the course -- between now and 2022. So that's into intra-basin demand. That's on to the Mainline through these gates. It's down to the GTN on West Path.

And beyond that it's going to be another 2.1 Bcf a day once we have Coastal GasLink pipeline built to the LNG facility on the West Coast. So lots of work going on right now. And we're always in discussion with our shippers around what the next path to market is.

We recently signed an agreement with Nauticol for 300 million cubic feet a day of supply into a new methanol facility that they're contemplating here in Grand Prairie. So those conversations continue all the time. And it's an important part of our dialogue. We need more market..

Okay, thank you. And maybe just as a follow up. Looking south of the border, I'm wondering what -- where the discussions are in terms of expansions on the U.S.

natural gas pipeline system there?.

So Linda this is Stan. I'll start and Tracy could add in if she wants to. Think of the U.S. pipes as a big catcher's mitt. GTN for example fully subscribed effective come 2020. We do have the ability to expand that pipe to the tune of about 0.5 Bcf a day. We think its competitive rates.

Moving forward across the system east, Great Lakes has about another Bcf of capacity that could take additional volumes from the Mainline. And then you've probably seen some of the success we've had on the East Coast with respect to expansions of our Portland natural gas transmission system.

That's being expended to the tune of about 60%, 65% more capacity than it has today. So think of the U.S. as a big catcher's mitt ready to receive all the growing production from Canada..

And what about expansion down to service more LNG off the U.S.

Gulf Coast?.

Yeah. Absolutely. Late last year we announced our Louisiana XPress project, a $400 million expansion to serve and establish the LNG export terminal. Just today we sanctioned another project called our Ground Engineer [ph] XPress project, a $225 million opportunity to feed a new LNG export terminal player.

So in the aggregate, you can think of LNG experts as growing to 10 Bcf a day over the next five to 10 years. With the positions we have at Ground Engineer, at Louisiana XPress and with our Cameron project that's about three Bcf of capacity to serve these terminals or about 30% of the market going forward..

That’s helpful. I’ll jump back in the queue..

Thanks, Linda..

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

Good afternoon.

Maybe I'll just build on that topic and – what is the dynamic as you're talking about Western Canadian producers about market? Is there a sense that you're getting, Tracy, as to where they want to go and whether they're willing to kind of piece together allow you to deliver multiple systems? Whether that's putting gas into the Gulf or with North Bay Junction swinging over-the-top and further into Northeast?.

Hi Robert, yes, there's lots of interest in doing that and in reaching any number of markets. Eastern Canada down to the Northeast U.S., down on -- or across our U.S. system as well as growing interest in the prospect of access through LNG and a global market off the East Coast as well.

I would say that it's mixed stability with the balance sheets in -- with across the producer community. In the basin, I would say that they're stepping into it in bits and pieces but we're also seeing market come to the basin to pick up gas. Most recently in our North Bay Junction open season, we saw market and the LBCs in the East.

In the Northeast U.S., we saw petrochemical in the East and we saw the Maritimes buy transport back to Empress in order to pick up the basin's gas. So, it's a combination of the producers willing to step out and the market willing to come back into the basin to get transport..

So, it sounds like you're seeing a pick up potentially here in demand poll? Is that kind of directionally what you've been seeing?.

Yes, there's. I think between the last two LTFP deals we've done, we've demonstrated that the basin's gas can get into Eastern Canada, Northeast U.S., now into the Maritimes competitively. And so those deals are in the money they're working and we hope to see more of that..

Okay, perfect. And maybe I'll just finish the question for Don. Looking at U.S. Tax Reform, you've got the statement of no material impact expected for the pipelines. I'm just wondering though do you have any thoughts here on the anti-hybrid rules? Whether that's U.S.

legislation or depths generally? And what you see the potential impact here being?.

Yes. For context these are proposed regulations that provide more definition to U.S. Tax Reform. These were released right near the end of 2018. They're quite complex and comprehensive. So, we're currently assessing the potential impact on our financing structures. It's a bit of a challenge as these aren't expected to be in final form until mid-2019.

Probably the best way to look at tax reform there's three elements to interest deductibility on the states. The first two came last year.

One was an absolute limitation 30% of EBITDA was your limit on interest deductibility with a carve-out for regulated utilities which the vast majority of our assets of our businesses actually fall under that exemption.

They introduced a minimum tax called the BEAT, Base Erosion Anti-Abuse Tax that was also restrictive of how much interest you can deduct there. And what they've done now is introduced basically a characterization test, if you will, as to the characterizing funding structures and how interest is channeled back through various corporate forms.

So, what we're doing right now is we're just assessing that. We could see some transactional impact -- transitional tax cost impact here until the final regulations are in place. But we're hopeful they won't have a material impact on our long-term cost to financing a U.S. operation. So, it's a bit of a stay-tuned right now.

We're just indicating that there's a lot of moving parts here right now and we're still interpreting that..

Okay.

And the potential impact or the uncertain impact, is that really what you're referring to in your outlook statement?.

Exactly. Yes. Directionally it would be a modest negative, but we don't know if that will manifest itself or how big that would be. And it may very well just be transitional for a short period of time here. So at this point, it's just again, flagging that this is out there.

And we're just looking at it and it's going to take a healthy chunk of 2019 to figure out what if any impact there is from it..

That’s great. Thank you..

Thanks, Robert..

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

Good morning or good afternoon, everyone. I want to transition over to Keystone XL. There is a number of processes in play.

I just want to get a sense of what your expected kind of path forward are for the Montana process, as well as kind of what are the key dates to ensure that you hit that 2019 summer construction window?.

This is Paul Miller here. Starting with Montana, we continue to work the Montana District Court decision. We had some success in having the injunction narrowed, but we are pursuing a path to have the decision reversed with the U.S. Department of Justice. And at this point we are waiting on a decision on that appeal from the District Court.

The other court challenge we have is in Nebraska Supreme Court on the PSC approval. That argument was heard back in late 2018 and we're waiting for the decision from the Supreme Court as well. We're also pursuing a couple of other State Department permits, one being the Bureau of Land Management and the Army Corps of Engineers.

And what's happening there is, in the Montana court decision the judge identified some deficiencies with the FCIS. And so State Department is going through additional work on our FCIS. We anticipate that they will complete their work through the comment period here by, let's call it, second quarter.

Following the issuance of the FCIS the state -- sorry, the Bureau of Land Management and the Army Corps of Engineers will be in a position to issue their decisions and their permits. In the meantime we continued to work some free construction activity that is allowed under the injunction.

But before we spend any material dollars, we will have to have resolution of these matters behind us..

All right. And then just to follow up on that.

So if the Bureau of Land Management and the Army Corps is not into a Q2 impact, like when would you have to start securing line crews to ensure that you get kind of full construction in that -- the warmer summer months?.

Yes. Our intent is to start construction in 2019 and we have a two-year construction window. But we also have an optimal construction program, which takes advantage of seasonality. It takes advantage of various construction windows that are available to us.

There will come a point where, because of the desire to pursue this optimal structure, we will lose 2019. We're not at that point yet. We continue to work these various hurdles, again, with a goal to achieving -- starting in 2019. But it's uncertain at this time when we will have these various legal and regulatory hurdles behind us..

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

Okay. Thanks, Rob..

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

Good afternoon..

Hi, Jeremy..

When looking at the NEB Mainline decision in December just what are the expectations around the pace that TRP will amortize the LTAA balance over the next couple of years? I know there's regulatory accounting and financial accounting. I'm just wondering, if you could provide a little bit more color there..

Hi, Jeremy, it's Don. So the – from an accounting perspective what we're looking at here is lower tolls and that will also lower taxes. So, that should – would modestly result in a modestly lower EBITDA. But from a net income basis that's from an accounting perspective fully offset in below the line in terms of lower income tax expense.

So we wouldn't expect it from an accounting perspective to have any major impacts. So a modest negative we'll call it on EBITDA modest being the key word there and neutral to earnings. From a geography standpoint, the deferrals that were collected are actually sitting in deferred amounts and other in investing activities not operating activities.

So this shouldn't have a major impact on cash flow. The drawdown of that balance will again just be within investing activities. A bit arcane, but I'm not sure if that helps..

That's helpful. And just when we look at the Liquids segment it seems like it's quite a nice step up quarter-over-quarter with regards to the Keystone in addition to the oil pipeline business development. I think you were expecting it to be kind of flattish year-over-year there.

I was just wondering is that kind of – you've locked in some attractive activity earlier in the year and that would dissipate over the course of the year? Or just trying to better understand the ratability of what's happening in the segment, because it seems like Keystone XL is kind of flattish up until this quarter?.

Jeremy, Paul again. I think when you look at the various components of the Liquids Pipelines business we're going to see 2019 look very similar to 2018 across all the components. The contracted segment will be relatively flat.

When I look at the spot that we've generated on both Keystone as well as Marketlink and I take a look at the current and future differentials, I would anticipate that we would see similar levels in 2019. And on the marketing affiliate same.

When I take a look at the capacity that they do hold the positions they hold in the markets in which they operate and the current and future differentials, I would anticipate seeing similar results to them as well. So year-over-year you're going to see 2019 very similar to 2018..

That's helpful. Thank you. That’s it for me..

Okay. Thanks, Jeremy..

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

Okay. Thanks. I want to go back to the Canadian Mainline. Just looking at the year-over-year EBITDA increase of $200 million, it looks like half of that's the depreciation that you've highlighted. And then there's $11 million of incentive earnings.

Just wondering, what's driving the balance of the increase just also given the rate base is also down 9% or so..

Ben, you have to look at – on the quarter all – the full impact for the year on the decision on 2018, 2020 tolls is registered in the fourth quarter. So you're seeing a lot of activity there. Don't get distracted by how big some of that looks. From incentive earning perspective, there's nothing big that's moving around.

If you look at the run rate at the end of the year, you can use that kind of as a proxy of what the run rate looks like going forward.

Does that make sense?.

I would try to supplement that Tracy. It's -- the other aspect there, that's noteworthy is recovery of income taxes. So as depreciation goes up, tolls go up revenues go up. So you collect actually more income taxes which shows up as part of revenue and EBITDA. But below EBITDA and tax expense, it's fully offset..

Ben, sorry it's David. For anybody else on the call, I'm more than happy to help you folks after the call kind of work through the quarterly amounts if you will and the run rates. So more than happy to do that..

Okay. That's great. And then my second question on the contrary around self-funding you inserted that language at Investor Day.

I'm wondering what do you think you need to see to get comfort in moving towards self-funding turn out to DRIP? And have you thought about just how your growth rate would look under that scenario?.

Yes. Sure. The -- so DRIP right now as I mentioned in my remarks, is really a quarter-to-quarter decision. And it's driven by a couple of things here. One is, operational performance and how we're tracking towards our target credit metrics and getting a comfort level that we will be in the high 4s and minimum 15% FFO to debt for 2019.

Important inputs into that are the cadence of our projects coming into service here. So we're watching that very closely. As noted, we expect the next couple of months to see $9 billion of assets fully placed in service here. That represents north of $1 million of EBITDA that is all contracted and regulated.

And as well asset sales, we've got Coolidge announced. We've got other processes at varying stages. We're not going to give a whole lot of definition to that. But we're -- if we can add more asset sales to truncate the DRIP program, we will do that..

And then the growth rate is 8% to 10% reasonable under self-funding?.

Under self-funding probably mid- to high single digits depending -- for low-risk assets the kind of stuff we've been doing for the past 20 years....

Yes. I mean as we've talked about before, I mean when you sort of ex all of the current funding that we've got on and the lag between the AFUDC earnings and cash flow, that's somewhat muddies the water.

When we run our model of reinvesting our free cash flow, and the debt capacity that comes from retained earnings, if we reinvest that into projects that return about 8% after tax which on average has kind of been our portfolio over the last 20 years we generated growth rate in the 7% to 8% range.

As we said at Investor Day like over the last 20 years, we've invested some $85 billion into our core assets and that's been our -- a little bit higher than our cash flow and earnings haven't had too many bumps in the road. And we've driven a growth rate in earnings per share cash flow per share and dividends per share at around 7%.

That's what I think sort of the true run rate of the company is. I would cite anomalous events like making large acquisitions like Columbia, where we had the opportunity to over-lever ourselves for a period of time. But at the same time build out expansion projects that had a greater return than the 8%. That led to that 8% to 10% through 2021.

As we look out beyond, I mean, my challenge to the team here as always we have to try to beat that 7% to 8%. But I think if you look at our history over the last 20 years that's what we've done. And for the last few years, we've been closer to the 8%, 9%, 10%.

But long run I would expect the number in that sort of 7% to 8% range very similar to what we've done for the last 20 years..

Okay. That's great. 7% is pretty attractive thing. Thanks everybody..

Thanks, Ben..

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

Yes. Hi, everyone. Good afternoon. A couple for me please. I guess if we can start there's been quite a lot of news in the north -- from the Northeast U.S. gas producers.

A lot of budget reductions still strong production growth near term, but I wonder if you might talk about that and what you're hearing from them and how that impacts potential growth maybe out the curb a little bit?.

Yes. This is Stan. I think what you're seeing is producers living within their means. And they have announced that they're cutting back some of the capital programs, which very well could mean a reduction in supply in the short term.

I'll tell you on our systems, when we put our Leach XPress project into service, which was 1.5 Bcf a day, we saw very strong flows 1.3, 1.4 Bcf a day. Our WB XPress project went into service this fall 1.3 Bcf and we're seeing consistent flows in the 1.1 Bcf a day range. So high usage there.

Mountaineer XPress we've had about between 1.1 and 1.5 Bcf a day capacity in service over the past month, but we've only seen nominations in the 500,000 to 800,000 a day range. So I think big picture what this tells me is that the producers are waiting for a little bit of a recovery in prices.

This very well could be the beginning of an overbuild to an extent in the U.S. where we have more capacity than we have production in the short term.

However, longer term as we look out over the next 10 years and see the potential for Marcellus to grow from 30, 31 Bcf today to 40 Bcf, we think that there's going to be a need for additional export capacity out of the region..

Okay. Thanks for that. I guess just maybe if I can go back to Coastal GasLink. It's -- you're very upfront about looking for a partner, trying to get down budgeting to the 25% of that project. Any update you can share on the partner process? There's been some talk that deals are a little slower in Canada right now.

And just any color you can provide there would be helpful?.

It's Don here. I just characterized it as not -- we're not experiencing that. We are very encouraged by the level and quality of interest to date and believe we're certainly on track for -- to bring in a partner or partners later this year..

So later this year? Can I just pursue? Is that we'll know something second half? Or a little bit first half?.

Probably second half, yes. The spend profile of Coastal GasLink is such we're certainly not desperate to get a partner in the very near term here. So we're taking our time. Again very broad interest high-quality names. And we're moving the process along here in the background..

I think combined with Dennis the nature of the capital spend being primarily in 2020 2021. Plus as we announced today all of our shippers have elected to pay the cash carrying cost with which again offsets the burden of any capital that we're going to be spending here in the short run..

Got it, got it. Thanks for that..

Thanks Dennis..

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

Sorry, I just wanted to follow-up on that line of questioning, specifically, confirm my understanding that the target of a high four leverage ratio, it includes the sale of a joint venture interest in Coastal GasLink.

And so if that's the case, if there is a delay to the process because of the jurisdictional challenge or otherwise, do you still intend to target the 4% -- the four times leverage? And what would be your avenue to get there?.

Yes, it's Don here again. Yes, we will absolutely target that high-4s leverage ratio. We -- from being in a JV partner here, I think it's the wait beyond this year which is not our base case nor our expectation. We're talking several hundred million dollars of spend this year that we would fully absorb.

So, it's not something material in the context of CAD100 billion balance sheet..

Okay. And then just there's been a lot of media I guess recently on the -- from the Mexican President on the force majeure payments being made on the pipelines among other things.

What's your take on that? And what's your strategy to deal with that situation?.

Hi Robert, it's Francois speaking. First, I think -- I'll provide a little bit of context here. As we talked about our investment and our capital outlay in Mexico in aggregate for the seven projects those -- between those in operation and those under construction, we've been guiding towards an aggregate EBITDA in the range of $575 million or so.

And with the four pipelines in operation being Tamazunchale, Mazatlán, Guadalajara, and Topolobampo and once we bring Sur de Texas into service here early in the second quarter, we'll be approaching $500 million of that $575 million. So, in terms of putting a context around the magnitude of the situation I thought that was appropriate.

We've made some comments here publicly earlier this week around the fact that the CFE pipeline contracts were the result of a public bidding process under Mexican law was transparent and in accordance with industry standards.

And in fact we were pleased to see the administration here reaffirm that they'll abide by their obligations under the contracts. It's actually correct. Our contracts include force majeure provisions that apply when either we or the CFE are prevented from fulfilling our obligations due to circumstances that are beyond our control.

But I would say that since the completion of our projects, it's clearly in the mutual interest of the CFE and TransCanada. Frankly, we welcome the opportunity to work with the government and with CFE to find solutions to the issues that are preventing their completion.

These projects supply much-needed natural gas to the country to supply gas for gas-fired generation, which shall result in significantly lower electricity cost and lower pollution. And so that alignment of interests gives us confidence that when we engage, and we are engaging with the CFE that those will be productive conversations..

Okay..

It's Don here. I'll just add to that. I'll just clarify that the force majeure payments are not in EBITDA. They're actually going to the balance sheet. So they're not something showing up in EBITDA number now..

Thank you..

Thanks, Rob..

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

Hi. Good afternoon, guys. Just a quick clarification to the wonderful detail you gave on the last question.

Are you basically saying that there is only CAD 75 million at risk once you get to the middle of 2019?.

Rounding it's in that order of magnitude. Recall that we provided disclosure here on the timing of the projects in-service Villa de Reyes towards the end of 2019 and Tuxpan-Tula in 2020. So, yes..

Okay. Perfect. As a follow-up question here. In terms of your targets to get to the high 4s in terms of leverage you've talked about traffic bills, Mexico and obviously Coastal GasLink have been on the list.

Does the jurisdiction discussion at the NEB impact your ability to monetize Coastal GasLink in the same thing with respect to these contract negotiations from Mexico? Like do these things have to be settled before a buyer will actually take a stake? Or is there an interest to supply these uncertainties out there?.

Yes. It's Don here. Firstly, I'll just state that we haven't indicated that Mexico is an asset that's on the block any portion of that. Coastal GasLink, no, we don't think the jurisdictional challenge is going to have any significant impact on our process of bringing in a JV partner..

All right. Perfect. Thank you very much. Appreciate the color. .

Great..

Thanks..

Thank you. [Operator Instructions] Next question is from Michael Lapides from Goldman Sachs. Please go ahead..

Hey, guys. Thanks for taking my question. And by the way to Karl, I don't know if he's listening in congrats on the retirement. Real quick. Just on the Coastal GasLink, one of the things I wanted to make sure I understood was the timeline.

Because it seems like you're doing a lot of the work -- a little bit of work in 2019 a lot of the work in 2020 and 2021. But if I remember, when Shell and the other owners started talking about the in-service date, I thought they kind of hinted at kind of late 2023, sometime in 2024.

So – and didn't really kind of hammer down an exact date, but it wasn't before the end – towards the end of 2023.

Just why have the pipe in service so much earlier or so much before the LNG facility will be around?.

Hi. It's Tracy. Yeah. We do have – we have agreement with LNG Canada around certain timelines to have the pipe in the ground. We'll take some time after that for commissioning and getting it in-service. And all that timeline should line up with roughly when LNG Canada will have their facility ready.

So, all this timeline works with the kind of commitment that we've made to LNG Canada..

And do you all have a view of when exactly LNG Canada's in-service target date is?.

I think that's something you'll need to talk to them about..

Got it. And one last thing speaking of LNG there's been obviously some talk about LNG on the Eastern Coast of Canada. Just curious there's one or two projects. They're very early stage.

How you guys are thinking about whether that's kind of realistic from a citing permitting contracting standpoint?.

Well, I would tell you that, we were doubters early on, but these – there's a number of proponents that are looking at Eastern LNG. And they continue to make progress. We're in discussions with all of them and they're all, I would say at various stages of the development of supply getting pipe capacity a position in LNG facility and finding market.

They're all in various stages of that, but some of them are very interesting. And certainly, they're all approaching it with a significant amount of intent. So we're watching that carefully. And we have not yet signed any agreements with any of them, but we are in dialogue with all of them..

Got it. Thank you for taking my questions..

Okay..

Thanks, Michael..

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 sir..

Great. Thanks very much and thanks to all of you. We very much appreciate your interest in TransCanada. We look forward to speaking with you again soon. Thanks and bye for now..

The call has now ended. Please disconnect your lines at this time. We thank you for your participation..