Thanks very much and good afternoon everyone. I'd like to welcome you to TC Energy’s 2019 first 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 Canadian Natural Gas Pipelines; Stan Chapman, President, U.S. Natural Gas Pipelines; Paul Miller, President of Liquids Pipelines; Francois Poirier, Executive Vice President, Corporate Development and Strategy, and President Mexican and Power & Storage; 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, it can be found in the investor 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 TC Energy 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.

They are provided to you in order to give you a better sense of TC Energy’s operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I will turn the call over to Russ.

Thank you David, and good afternoon everyone and thank you very much for joining us here late on Friday afternoon, we recognize it's been a busy week for most of you. Before providing an update on our progress that we've made over the last three months, I'd like to thank our shareholders again for supporting our name change earlier today at the annual meeting.

As explained when we announced the change in January, we believed that TC Energy better reflects our current position as one of North America's leading energy infrastructure companies with critical assets and dedicated employees across three countries Canada, the United States, and Mexico. Turning to our progress, in early 2019, as highlighted in our quarterly report to shareholders, during the first quarter, our $100 billion portfolio of high-quality long-life energy infrastructure assets continued to perform from strong supply demand fundamentals in the core geographies that we serve.

And we continue to relies on the growth expected from our industry leading capital expansion program has replaced new long term contracted and rate regulated assets into service. In a nutshell, the demand for our infrastructure remains strong driving historically high utilization rates across all of our systems.

That combined with new assets entering service resulted in record first quarter earnings and cash flow. Evidence of this can be seen in our comparable earnings of $1.07 per share for the three months ended March 31, 2019.

During the quarter, we also placed approximately $5.3 billion of new assets into service, including the Mountaineer and Gulf XPress projects on our Columbia systems as well as various NGTL system expansions. Today, we are advancing approximately $30 billion of secured capital projects with approximately $7 billion of those projects expected to be completed by the end of this year.

We also continue to advance over $20 billion of projects under development including Keystone XL, and the refurbishment to five additional reactors at Bruce Power as part of their long-term life extension program. In addition, we continue to make progress funding our capital ground by raising approximately $1.2 billion early in 2019.

That included $1 billion of 30-year term debt, which was issued in April at compelling rates and $226 million of common equity under the dividend reinvestment program. We also remain on track to complete the sale of our Coolidge generating station in Arizona for approximately USD465million by mid-year and continue to progress in various other portfolio of management activities.

Looking forward, we expect our strong operating and financial performance to continue, and therefore, 2019 comparable earnings per share are expected to be higher than the record results we produced in 2018. At the same time, our overall financial position remains solid and we believe that we're well positioned to achieve our targeted credit metrics in 2019.

Don will provide more detail on our first quarter finance results in funding in a few moments, but before that, I'll expand on some of the recent developments beginning with a brief review of our financial results. Excluding certain specific items, comparable earnings were $987 million or $1.07 per share in the first quarter, an increase of $123 million or $0.09 per share over the same period in 2018.

That equates to a 9% increase on a per share basis after recognizing the effect of common shares issued under the dividend reinvestment program in 2018 and 2019, and our ATM program in 2018. Comparable EBITDA increased $320 million to approximately $2.4 billion, while comparable funds generated from operations of $1.8 billion were $180 million higher than the first quarter of 2018.

Based on the strength of our financial performance and our growth outlook, Board of Directors today declared a second quarter dividend of $0.75 per common share, which is equivalent to $3 per share on an annual basis. This represents an 8.7% increase over the amounts declared in the second quarter of 2018 and equates to a payout of approximately 75% of comparable earnings and 40% of internally generated cash flow, leaving us with a financial capacity to continue to invest in our businesses.

Next, I'd like to make a few comments about out five operating businesses. Firstly, in Canadian natural gas, customer demand for access to our systems remains strong and we continue to work with the industry on options to connect growing Western Canadian gas just two markets across North America.

Evidence of that demand for our services can be seen in the volumes that we transported across our network. Our NGTL system delivered an average of 13.5 billion cubic feet a day in the first quarter.

Consistent with the volume that we transported over the same period last year. On the Canadian mainline, total deliveries averaged 5.9 billion cubic feet a day in the first quarter.

Today, we are advancing about $8.6 billion on the end -- of expansion program on the NGTL system that will add approximately 3 billion cubic feet per day of incremental delivery capacity to the system by the end of ’22. We also continue to actively work with LNG Canada on our coastal gasoline pipeline project following a positive final investment decision last October on their LNG terminal in Kitimat, British Columbia.

The $6.2 billion pipeline project will have an initial capacity of 2.1 billion cubic feet a day, with the potential of expansion up to 5 billion cubic feet a day. All of the necessary regulatory permits have been received to allow us to proceed.

And pre-construction activities continue at many locations along the pipeline route. Moving to our natural gas -- our US natural gas pipelines, the demand for our services reached record levels.

As highlighted previously, our broad network has historically served about 25% of the US demand on a daily basis. More recently, winter deliveries averaged 24.4 billion cubic feet a day and the cold temperatures that grip much of North American in late January and early February led to a peak day delivery record for our company in the United States of 33.1 billion cubic feet a day on January 30.

In addition to moving record volumes on our existing US systems during the first quarter, we continue to advance $5.8 billion of secured expansion projects. Columbia's Mountaineer Xpress, along with Gulf XPress projects were phased into service over the first quarter of 2019.

At the same time, we continue to identify new opportunities across our broader US natural gas pipeline portfolio to connect Marcellus and Western Canadian sedimentary supply to markets. An example of that is our Grand Chenier XPress project, which was sanctioned in February.

It's an A&R pipeline project that will connect supply directly to the Gulf Coast LNG export markets through additional compression facilities. Subject to a positive customer FID, the project is expected to enter service in two phases over the 2021 and 2022 period at a cost of about USD200 million.

Turning to Mexico, where we're battling construction on three pipelines at a total cost About $3 billion while the sure to set sort of Texas pipeline has experienced for some mature events that have delayed in service construction and commissioning activities are progressing, such that we anticipate mechanical completion in May, with an expected to and in service date. Construction on the theater a project is ongoing with a phase in service anticipated to commence in the second half of 2019.

Turning to Mexico, where we're advancing construction on three pipelines at a total cost about $3 billion. While the Sur de Texas pipeline has experienced force majeure events that have delayed in service construction and commissioning, activities are progressing such that we anticipate mechanical completion in May, with an expected June in-service date.

Construction on the Villa de Reyes project is ongoing with a phase in-service anticipated to commence in the second half of 2019. And finally, the construction on the central segment of the Tula project has been delayed due to lack of progress on indigenous consultations by the Mexican government.

As a result, we expect that project to enter service towards the end of 2020. We have negotiated separate CFE contracts that would allow certain segments of the Tula and Villa de Reyes project to be placed in service when the facilities are complete and gas is available.

Turning to our liquid business which produced very strong results in the quarter. Keystone which is underpinned by long haul take or pay contracts for about 550,000 barrels a day essentially ran at capacity in the first quarter, moving an average of 590,000 barrels a day.

On the southern portion of the system, or what we call the US Gulf Coast segment, capacity was increased throughout 2018, reaching approximately 700,000 barrels a day by year end. As capacity increased, we maintain near fully utilization rates in the fourth quarter and a gain into the first quarter of 2019.

In addition, we continue to benefit from higher contribution from liquids marketing activities, largely due to improve volumes and margins as a result of favorable market conditions. On the project development side, commissioning has been completed on the $200 million White Spruce pipeline and commercial in-service was achieved here early in May.

Also, in the first quarter, we entered into an agreement with Motiva to construct a pipeline to connect between the Keystone pipeline system and Motiva 630,000 barrels a day refinery in Port Arthur. That connection is targeted to be operational in the second quarter of 2020.

Finally, in the liquid business, in the first quarter, we continued to advance Keystone XL. In late March, the US President issued a new presidential permit for the project which supersedes the 2017 permit.

The President's actions clarify the national importance of Keystone XL and aims to bring more than 10 years of environmental review to closure. President Trump has been clear that he wants to create the jobs and advance US energy security and Keystone XL does both of these things in an environmentally sustainable and responsible way.

We thank him for his leadership and steadfast support of this critical energy infrastructure project. Also, with respect to Keystone XL in Nebraska, as you know, we received approval of the route in the state, however, as you know, that decision has been challenged.

We expect the Nebraska Supreme Court could reach a decision in the second quarter of ’19 with respect to an appeal of the Nebraska Public Service Commission's approval of our route. We continue to participate together with the US Department of Justice in lawsuits commenced in Montana to defend legal challenges to the US Presidential permit and the exhaustive environmental assessments that support the US President's actions.

We've secured commercial support for all available capacity on the Keystone XL system and we remain committed to the project. We continue to clarify, to carefully and methodically obtain the regulatory and legal approvals necessary before we advance the project to construction.

Turning out to power and storage, which was previously known as the energy segment, the name change was made to better describe our assets and operations in the segment. It does not imply any change in strategy or have any impact on previously recorded segmented results.

In power and storage, we experienced equipment failure on the $1.7 billion Napanee project while progressing conditioning activities on the plant during the first quarter. As a result, we now expect the 900 megawatt plant to be placed into service in the second half of ‘29 once that equipment is repaired.

Work also continues on the Bruce Power Life Extension Project where we expect to invest approximately $2.2 billion in Bruce Power’s unit six program as well as ongoing asset -- as the ongoing asset management program through 2023 when unit six refurbishment is complete. Bruce Power’s contracted price of approximate $68 per megawatt hour increased to approximate $75 per megawatt hour on April 1.

2019, to reflect the capital to be invested under these programs as well as a normal annual inflation adjustment. Finally, in the power and storage segment, we have entered into agreement to sell our Coolidge generating station in Arizona for approximately $465 million or CAD620 million.

The sale expected to close mid-2019. This way sale allows us to surface significant value for mature assets that represented less than 10% of our generating capacity, and then redeploy that capital into our $30 billion secured capital program thereby reducing our need for external capital including common equity.

So, in summary, today we are advancing $30 billion of secure projects that are expected to enter service by 2023. It includes approximately $5 billion of maintenance capital, 85% of which is related to our rate regulated natural gas pipelines and, therefore, is expected to be added to rate days and generate a return on enough capital identical to that which we realize on expansion projects.

We've invested approximately $10 billion into that program to date, with approximately $7 billion of those projects expected to enter service in 2019. The projects expected to be completed this year includes the $2.8 billion of the NGTL expansions as well as the Sure de Texas natural gas pipeline in Mexico, and the Napanee gas-fired power plants in Ontario.

Notably, all of these projects are underpinned by cost of service regulation or long-term contracts giving us a high degree of visibility to the earnings and cash flow that we generated as they enter service. This highlights the significant growth in EBITDA that is expected as we continue to advance our secure capital program, as you can see on this chart, comparable EBITDA, which has increased from $5.9 billion in 2015, to $8.6 billion in 2018, is expected to reach approximately $10 billion by 2021.

That equates to a compound average growth rate of about 9% over the six-year period. And just as important as the magnitude of that growth is the quality of the growth with over 95% of our EBITDA coming from regulated assets or long-term contracts.

In addition, as I said, we are advancing $20 billion projects currently under development, any one of those projects could further enhance our growth profile as well as our strong competitive North American position. Based on our confidence in our growth plans, we expect to continue to grow the dividend at an average annual rate of 8% to 10% through 2021.

And, as always, has been our practice, the growth of dividend is expected to be supported by sustainable growth in earnings and cash flow on a per share basis and strong distributable cash flow coverage ratios. So, in summary, I’ll leave you with the following key messages.

Today, we are a leading North American energy infrastructure company with a strong track record of delivering long-term shareholder value. Our assets are critical to the functioning of the North American economy and the demand for our services remains strong.

In 2018, our $100 billion asset portfolio generated $8.6 billion of annual EBITDA with approximately 95% coming from regulated businesses or long-term contracted assets. Looking forward, we have five significant platforms for growth, Canadian, US and Mexican gas pipelines, liquids pipelines, and power and storage.

Just as we have done since 2000, as we advanced our $30 billion secured capital program, we expect to deliver continuous growth in earnings and cash flow and dividends on a per share basis. In addition, we have over $20 billion of projects that are in the advanced stages of development and we expect numerous other growth opportunities to M&A from our existing extensive critical assets footprint.

We have a long history of prudently funding our capital programs and we are on track to continue to delever our balance sheet post 2016 acquisition of Columbia and achieve our targeted credit metrics here in 2019. That concludes my prepared remarks.

I'll turn the call over to Don to provide more details on our first quarter financial results.

Great, thanks Russ, and good afternoon, everyone. As outlined in our quarterly report issued earlier today, we're pleased to report that net income attributable to common shares increased by $270 million to $1 billion or $1.09 per share in the first quarter of 2019 compared to $734 million or $0.83 per share for the same period in 2018.

First quarter 2019 and 2018 results included an after tax loss of $12 million and an after tax gain of $6 million respectively, related to the run off of our US Northeastern power marketing contracts. These specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings.

Comfortable earnings in the first quarter rose by $123 million to $987 million or $1.07 per share compared $864 million or $0.98 per share in 2018, representing a 9% increase on a per share basis. Per share amounts account for the dilutive impact of common shares issued under our dividend reinvestment plan at 2018 and 2019, and at the market program in 2018.

Our positive results reflect brought operational strength and solid cash generation, particularly in Canadian and US natural gas pipelines, along with liquids pipelines. Turning to our business segment results on slide 15.

In the first quarter comparable EBITDA from our five operating businesses was approximately $2.4 billion, a $320 million or 16% increase year over year. Note that we do not include AFUDC which amounted to $139 million in the quarter in EBITDA.

As outlined in the quarterly report, Canadian natural gas pipeline’s comparable EBITDA of $556 million was $62 million higher than for the same period in 2018. The increase was primarily due to the recovery of depreciation and increased rates approved in both NGTL in 2018 and 2019 settlement and the Mainline NEB 2018 Decision as well as higher flow through taxes and incentive earnings.

In terms of year over year comparison, as a result of the timing of the NEB 2018 decision, the full year impact of higher depreciation flowing through taxes and incentive earnings on the Mainline was not reflected until the fourth quarter of 2018. I would note that for Canadian natural gas pipelines, changes in depreciation, financial charges and income taxes impact comparable EBITDA but do not have a significant impact on net income as they are almost entirely recovered in revenues on a flow through basis.

Net income for the NGTL system increased $21 million compared to first quarter 2018 because of a higher average investment base and reflects an improved ROE of 10.1% on 40% deemed equity. Net income for the Canadian Mainline increased by $7 million for the three months ended March 31, 2019, compared to the same period last year, mainly due to higher incentive earnings.

The 2018 NEB decision previously mentioned preserved the incentive arrangement in place since 2015 along with an improved ROE of 10.1% on 40% deemed equity. US natural gas pipeline’s comparable EBITDA of USD730 million or CAD972 million, increased by USD95 million or CAD168 million compared to the same period in 2018, mainly due to increased earnings from Columbia Gas and Columbia Gulf growth projects placed in service partially offset by decreased earnings in Bison due to 2018 customer agreements to pay out their future contracted obligations and terminate their contracts.

Mexico natural gas pipeline’s comparable EBITDA of USD110 million or CAD146 million, decreased USD17 million or CAD14 million compared to first quarter 2018, driven primarily by lower recorded revenues from operations as a result of changes in timing of revenue recognition in 2018 and lower equity earnings from our investment in the Sur de Texas pipeline. Note that while in construction, Sur de Texas records AFUDC, net of interest expense on an inter-affiliate loan, which amount is fully offset in interest income and other in the corporate segment.

Liquids pipeline’s comparable EBITDA rose by $132 million to $563 million driven by higher volumes on the Keystone pipeline system and a higher contribution from liquids marketing activities as a result of increased volumes and margins. As mentioned by Russ to better describe our assets and operations, the previously disclosed energy segment has been renamed power and storage.

Comparable power and storage EBITDA decreased by $25 million year over year to $151 million due to decreased western and eastern power results largely resulting from the sale of our interest in the Cartier Wind power facilities in October 2018 and costs related to Napanee's delayed in-service. These were partially offset by wider realized natural gas storage price spreads and stronger Bruce Power results due to the net effect of positive fair value adjustments and other returns on investment supporting employee post-retirement benefits and lower volumes and revenue resulting from higher outage days.

For all our businesses with US dollars denominated income, including US natural gas pipelines, Mexico natural gas pipelines, and parts of liquids pipelines and power and storage, Canadian dollar translated EBITDA was positively impacted by a stronger US dollar versus the first quarter of 2018. This was largely offset by higher translated interest expands on US dollar denominated debt and realized hedging losses reported in comparable interest income in other.

As our US dollar denominated operations continue to grow, our exposure to foreign exchange movements will increase, a sizable portion of which is naturally offset by interest expense on US dollar denominated debt. The residual balances actively managed on a rolling one-year forward basis using foreign exchange derivatives.

However, the natural exposure beyond that period remains. Now turning to the other income statement items on slide 16, depreciation and amortization of $608 million, increased $73 million versus first quarter 2018, largely on account of higher composite depreciation rates approved in the Mainline NEB 2018 decision and the NGTL 2018-2019 settlement.

New facilities entering service across our businesses and the impact of a stronger US dollar partially offset by the sale of our interests in the cartoon Cartier Wind power facilities in 2018 and the cessation of depreciation on our Coolidge generating station upon classification is held for sale at December 31, 2018. Interest expense included a comparable earnings of $586 million, was 59 million higher year-over-year as a result of new long term debt issuances, net of maturities, higher levels of short-term borrowing and the foreign exchange impact of a stronger US dollar on translation of the US dollar denominated interest, partially offset by higher capitalized interest related to [indiscernible] and Keystone XL.

AFUDC rose by $34 million to 139 million for the three months ended March 31, 2019 compared to the same period in 2018. An increase in Canadian dollar denominated AFUDC was primarily due to capital expenditures on our NGTL system, while an increase in US dollar denominated AFUDC was driven by continued investment in US natural gas pipelines and Mexico projects Comparable interest income and other declined $34 million year-over-year, primarily as a result of realized hedging losses on foreign exchange management in the first quarter of 2019 compared to realized gains in 2018, partially offset by higher interest income related to the intra affiliate loan receivable from the Sur de Texas joint venture described earlier, 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 228 million in first quarter 2019 compared to 171 million for the same period last year, primarily due to higher comparable earnings before income taxes, higher flow through taxes in Canadian natural gas pipelines and lower foreign tax rate differentials.

Net income attributable to non-controlling interest increased by $7 million for three months ended March 31, 2019, mostly due to higher earnings in TC PipeLines, LP and the impact of a stronger US dollar in 2019 on their translation to Canadian dollars. And finally, preferred share dividends were comparable to first quarter 2018.

Now moving to cash flow and distributable cash flow on slide 17. Comparable funds generated from operations were approximately $1.8 billion in the first quarter, reflect an increase of $180 million year-over-year, driven largely by higher comparable earnings as well as the recovery of higher depreciation for both the Canadian mainline and NGTL system.

Distributable cash flow reflecting only non-recoverable maintenance capital was just over $1.6 billion or $1.76 per share, compared to approximately $1.4 billion or $1.63 per share in the first quarter of 2018, resulting in a coverage ratio of 2.3 times. Now turning to slide 18, during the first quarter, we invested approximately $2.3 billion in our capital program and successfully funded it primarily through our strong and growing internally generated cash flow, notes payable and common equity from our dividend reinvestment plan.

Our dividend reinvestment plan or DRIP continues to provide incremental subordinated capital in support of our growth and credit metrics. In the first quarter, the participation rate amongst common shareholders was approximately 33%, representing $226 million of reinvestment.

Also in the first quarter, we received a distribution of $120 million from Bruce Power, relating to their issuance of senior notes in the capital markets. In December last year, we entered into an agreement to sell our Coolidge generating station for approximately USD465 million or CAD620 million.

The sale was subject to a third party right of first refusal, which was subsequently exercised and will result in an estimated $55 million after-tax gain to be recognized upon closing of the transaction, which is expected to occur in mid-2019. In April, we raised $1 billion through an offering of 30-year senior unsecured notes in the Canadian market at a rate of 4.34%.

Funding activity continues to highlight the depth and diversity of the financing options available to us, allowing us to prudently fund our capital program and achieve targeted credit metrics. Now, turning to slide 19, this graphic highlights are forecasted sources and uses of funds through 2021.

Starting in the left column, the gross funding requirement over the next three years is projected to be $29 billion, comprised of dividend and non-controlling interest distributions of approximately 10 billion and capital expenditures of approximately 19 billion, including maintenance capital. As a reminder, we are pursuing joint venture partners as well as potential asset level financing toward funding the $6.2 billion Coastal gasoline project.

The expenditure will be spread over approximately four years with the bulk of it in 2020 and 2021. For purposes of our funding program outlook, we assume we retain a 25% interest in Coastal gasoline, which is reflected in our capital requirements.

The second column highlights aggregate sources including approximately $21 billion of internally generated cash flow, an estimated $700 million of proceeds from our dividend reinvestment plan for the January through July 2019 dividend payments, as well as $620 million of proceeds from the sale of Coolidge generating station. That leads to capital markets requirement of approximately $6.7 billion in the far right column.

Aside from refinancing normal course maturities, we expect to issue approximately $3 billion of incremental senior debt through 2021 within the constraints of retargeted credit metrics and debt to EBITDA in high-4s 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 $2.2 billion, as illustrated in the top right box, will be comprised of activities such as incremental DRIP proceeds beyond the dividend most recently declared and portfolio management. DRIP remains a quarter-to-quarter decision, influenced by financial performance against targeted credit metrics, along with the cadence of getting new assets into service and the timing of asset sales.

Aside from Coolidge, we have assets generating approximately $500 million in 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, [indiscernible] should not be construed as an activity. In summary, we believe our external funding needs are eminently achievable in the context of the multiple financing levers available and the clear, accretive and credit supportive use of proceeds.

All decisions are evaluated on a per share basis, and further share count increases will be assessed against additional portfolio management. We reiterate that we do not foresee a need for the street equity to complete our secured $30 billion capital program, and our goal is to revert to our historical self-funding model as expeditiously as possible.

In closing, I’ll offer the following comments. Our positive financial and operational results in the first quarter continue to highlight our diversified low risk business strategy and reflect the strong performance of our legacy portfolio bolstered by continuing additions of high quality assets from our ongoing capital program.

Today, we're advancing a $30 billion suite of secured projects and have five distinct platforms for future growth in Canadian, US and Mexico natural gas pipelines, liquids pipelines and power and storage. Our overall financial position remains solid, supported by our strong credit ratings and a straightforward capital structure.

We remain well positioned to fund our near term capital program through resilient and growing internally generated cash flow and ready access to capital markets on compelling terms, supplemented further by capital recycling. We will continue to make all funding decisions through the lens of per share metrics.

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 of 8% to 10% through 2021.

Success in adding to our growth portfolio in the coming years could augment or expand 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 ask that you limit yourself to two questions. And if you have any additional questions, please re-enter the queue.

With that, I'll turn it back to the conference coordinator.

Hi, good afternoon. Just wanted to start off with Keystone XL here and want to understand if FID has not been made at this point because of other issues outstanding with Nebraska and so on, how does that impact, I guess, the potential timeline if you were going to take FID, it seems like you would have had to get the construction crews by now.

So maybe construction wouldn't happen this summer and the timeline kind of be pushed back a bit here. And also just want to know how you think that impacts your kind of -- your balance sheet and your leverage metrics and thoughts on portfolio management, it seems like there's some reports out there by some sizable packages that that could happen.

Jeremy, it’s Paul here. I'll start with the first question revolving on the construction timing on Keystone XL.

We continue to work through the various legal and regulatory issues that we have in front of us and resolution of these will be critical to us moving forward on an FID decision. In the meantime, we have and continue to work on some construction preparation activities.

But with the current injunction imposed on us, our ability to pursue a lot of those activities is somewhat restricted. So at this point, we have lost the 2019 construction season in the United States.

We continue our construction planning, continue monitoring our progress on the various litigation that’s out in front of us. And once resolved, we’ll make a determination on a construction start and duration of that construction program.

In regard to engaging resources such as contractors, et cetera, we continue to deal with the marketplace, but we also continue to be very disciplined in our capital spending and what commitments we're going to make in the face of uncertainty.

Jeremy, it’s Don here. Firstly, with respect to portfolio management, we don't comment on specific rumors or processes running, unless they are in the public domain, but -- and I wouldn't necessarily tie anything underway right now to cash out directly.

We look at portfolio management more holistically as is something normal course in our DNA now, in terms of capital recycling. In terms of KXL funding, specifically, we continue to look at funding scenarios that will refine as we get through the regulatory stage gates and closer to an FID and we get better cost and timing certainty.

If we're actually proceeding on that front, as we mentioned before, it's likely an all of the above strategy. Probably not a lot of senior debt capacity through construction, given our credit metric targets and absence of any cash flow would be in service.

Certainly, portfolio management continues in the normal course here. Cash that would bring some hybrid capacity, probably 15% of the balance sheet growth would be funded through hybrids.

We would actively consider joint venture partners in terms of looking at the finance load per share metrics and risk sharing. And equity, if required, probably would be required in some form, could look through the DRIP, the ATM, discrete issuance or some permutation.

It's kind of all open ended, but we continue to work through cost timing and risk sharing. And, again, an all of the above strategy on the funding side.

That’s helpful. Thanks for that.

And just turning to the liquids side, it seems like you guys have exceeded our estimates once again there. And so I was wondering if you could just help us think through the level of kind of ratable earnings, granted you guys -- the vast majority of your earnings are stable, but there is a component that is -- you're able to kind of capture spreads out there and just wondering if you could give any type of sense for how much of that is already locked in this year, just trying to better gauge how we think about the earnings potential from that segment.

Sure, let me walk through the components, Jeremy. So, to your point, a good portion of the liquids business, particularly around the Keystone pipeline system is locked in the system itself.

The pipeline itself is 94% contracted with long term take or pay contracts and then the other 6% that we have for spot is largely utilized. So, I would anticipate that portion to see similar results, quarter-over-quarter, plus or minus $0.05.

The variability you see potentially is on the market link portion of the Keystone pipeline system. And it's kind of good variability in that we continue to increase the capacity on the Southern leg of our system.

At Investor Day last year, I indicated that we will be targeting about mid-700,000 barrels per day range on the Southern end and we achieved that in first quarter. And you see that in the quarter-over-quarter results where probably about $0.02 of that increase is attributable to the higher volume on market link.

And as is our practice, as we increase this capacity, we look to lock it down by a way of long term contracts and we are in the marketplace today trying to lock down that incremental capacity with contracts. Another component of the variability is the liquids marketing results.

Quarter-over-quarter, you saw similar results and our results can be driven largely by the market differentials, particularly the Brent TI spread. And when you look at where the spread was last quarter versus Q1, ultimately equal, you saw similar results.

Going forward, Q2, with what we have locked down and where the market is at, I would anticipate Q2 would be very similar. Q3 and Q4 on the forward curves, we see some weakness.

We will go in and out of the market as we see opportunities. But with the forward curves today, I would anticipate Q3 maybe $0.01 to $0.02 lower than what we saw in Q1 and anticipate in Q2.

And depending on where the market moves and our performance, we may see yet another penny decline in Q4. But we will go and take advantage of those opportunities in the marketplace as they present themselves.

Thank you. On page 18, you cite a simple understandable corporate structure and you're substantially there.

I did notice you were silent in terms of mentioning TC PipeLines. Can you give us a comment on how you think Trans -- TC Pipeline fits into TransCanada over the long term, and how do you continuously assess the merits of it to remaining MLP in your strategy.

It’s Don here. These are core assets.

But I would also note that versus peers in the industry, [indiscernible] is a fairly small portion of $100 billion balance sheet, so it's not a pervasive vehicle for holding our assets. I would continue to describe the LP as neither a source, nor a use of capital at this time.

Dropdowns are not a viable funding option right now, but we continue to monitor the LP, but I would say, there's no distinct plans at this point to make any strategic moves to change things up there.

And just a question now on the NGTL application. I'm wondering, maybe this is a question for Tracy, how might this kind of enhance the service offerings you can provide customers and maybe your business objectives?

Are there any contentious aspects, given that the regulator has decided to go to an oral hearing? And could we see the main line rate design and services evolve as well over time?

Is this part of a bigger, grander plan, and maybe you can just give us an update on how you're thinking about that?

The application that went in on the NGTL was on great design and it had two purposes really. We restructured the design to more accurately reflect how volumes flow now on the NGTL system.

So there were some changes in tools and services related to that. And secondly, it took on this issue of how we told the North Montney Mainline.

You will recall that we received some feedback from the board that a full rolling on North Montney, they felt wasn't appropriate. We continue to believe it is appropriate.

But, we took the guidance from the Board of a surcharge. So, part of that application is a surcharge on the North Montney Main line.

So that is, the piece is going to go to a hearing from the board. It's very complex, it's very large, it expands the full scope of the NGTL system.

And there are different points of view on it. There are folks like us who believe Montney should be a full roll-in and there are others who believe it should not be.

So, the board has decided to have that dialog for hearing. And they have scheduled that hearing now.

As it relates to the Mainline, we are in process of a very interesting dialog with our customers right now. As you know, at the end of 2020, the rate base will separate between the Western mainline and the eastern part of that network.

And that gives us some options, some flexibility to think about tools and services a little bit differently on that line. So that's dialog that's underway right now and we would expect it to culminate Later this year, earlier next year with the application to the board for the next iteration of the structure for the Mainline.

In all cases, what we're looking for are answers that will facilitate the competitive access of the basement volume to market. We have a base and that’s prolific, we’ve got some great wells, very competitively priced gas, and we want to be helpful in getting it into market.

Thank you. And is this something that will get an update on maybe at your Investor Day this fall or sooner in terms of how it might be evolving?

Or is it still very early?

I think it's still very early. It depends on how those conversations go.

And so it may be an Investor Day, may be a little bit later, depending on, I mean, it's very complex topic and lots of different options as we think about the full kind of flexibility that we have for us as an industry. So later this year, perhaps.

I would like to circle back on your comments on Keystone XL. Specifically, how you think the path forward is in terms of the development timeline here?

Will you kind of take your foot off the gas and wait until you get all the legal and regulatory challenges behind you? And also, how do you think about building a pipeline into the next administration?

It’s Paul here. I think the best way to describe it is our focus is managing the legal and regulatory items in front of us, because those ultimately have to be resolved before we move forward.

In consultation with our shipper group, we remain disciplined in what resources we commit today to allow us to potentially start construction. But we will not make any major capital commitments until we have a clear path to construction and that determination will be made once we have greater clarity around the legal and the regulatory hurdles in front of us.

All right, and then thoughts on building it into the next administration.

The next administration is going to be what it is. Keystone XL is a very important project for industry and it's very important project for North America.

And the construction starts and the duration may overlap into the next administration. We don't know.

But ultimately, we will move forward with the Keystone XL when we have all the necessary approvals, when we have identified and assessed all the risks, and having those regulatory and legal issues behind us provide us with a level of comfort that we’ll ultimately be able to construct this pipeline in normal course.

All right, thank you for that. And then just switching over to the Coastal gas link, when you look at the schedule there, are there any key choke points we should be aware of that could push the schedule off there.

No, Rob. There aren't at this point, so we are under construction, largely pre construction activities along a numerous points along that bypass.

Primarily, clearing and setting up the camps, we will be into the heart of construction of laying pipe next year in 2020. And as of now, I mean, it's very early on the project, but as of now, we are roughly where we expect to be, a little bit behind in the territory that, in which we've had some opposition, but we now have full access to the pipe cap in our remaining constant dialog with all of our partners including the First Nations along the right away.

So we are where we need to be right now.

I think I’ll follow up on the Coastal gas line. As we go through the process here for the jurisdictional challenge, are you getting any sense of what transitional provisions if any might be applicable should the jurisdiction change as part of this process?

In other words, do you have the -- what's your sense of what you need to do, if you have to change jurisdiction in terms of project review?

Robert, I would tell you, we are in the final stage of that process right now yesterday and today. Our teams are in front of the NEB with the oral submissions, which is the final step.

And I would note that we still -- we continue to believe that this project is properly positioned within the provincial jurisdiction of British Columbia. I would note that, based on the evidence that's been submitted in the process, the Attorneys General of Canada of -- and of the provinces all to have taken the same position.

So we remain optimistic that that will be the outcome. There is precedent, as you know, if the NEB were to decide differently and point us towards a federal jurisdiction, there is precedent as to how that transition would take place.

And it would be our expectation that that would be a very orderly transition.

Okay. And then, I mean, other than reducing your ownership of Keystone XL, are there any other updated thoughts you could share on strategies to mitigate that last mile risk, particularly now, because it doesn't look like it goes through another administration?

Are there any other risk sharing mechanisms with shippers that are under consideration?

Well, what we do have today, we're sharing mechanisms with shippers on the development costs, 50-50. But as we assess the last mile risk, we continue to methodically work the various issues in a very disciplined fashion.

And the key to the last mile risk is really to plan and prepare and minimize that variability and ultimately assess your efforts to mitigate the last mile risk, leading into an FID. Where we're at today, we continue to identify and mitigate those risks, but ultimately, it's going to be at FID where we make that ultimate call on how good of a job we've done.

I guess what I'm getting at here is, is there – have you socialized these with rating agencies and lenders or do you approach your funding strategy differently in the current environment? Or is it sort of all of the above, as you indicated earlier?

It’s Russ. That's getting ahead of where we are.

First of all, we have to determine whether we can get the permits and all the legal issues that are in front of us today. At that point, we can assess what the risks are.

At that point, we can assess how we're going to finance it, mitigate any risk left at the end of that period. So we're not at that point yet where we can have those conversations with those parties.

We do continue, as Paul said, to have conversations with our shippers who have all indicated the importance of this project, both producers in Canada, the United States and refiners and as well, you would note that there is a large conversation going on in the media right now on the importance of egress leaving Western Canada and the importance of that. So all of those things will be considered at the right time.

But it's premature to be considering the rating agency comments and those kinds of things. Because at this point in time, frankly, we don't have anything to put in front of them.

Probably a question for Stan. Just turning to the US gas pipeline side of things and the opportunities that are in front of you.

There's, within the projects under development, this other capacity capital, 700 million. You also have the 500 million under secured, I don't know if there's been some movement from the annual, but in the project under development, that's new.

Just wondering what types of things are you looking at and how does this tie back and two, what you had at Investor Day in terms of the eight or so projects that you highlighted.

So Robert, this is Stan. It is quite consistent with what we showed you at Investor Day.

There has been some movement on the capital payable and the projects that are under development that you're referring to are projects that are essentially commercially secure but are still subject to FID by our counterparties. So we moved them over in that respect.

With respect to what's potentially coming down, I would say the fundamentals in the industry, particularly in the US point to growth in terms of increased production, they point to LNG growth, and they point to growth in Powergen. And as we sit right now, we have projects in various stages of origination across virtually all of our pipes in the US.

I would expect that perhaps as early as later this year, you're going to see another supply push project, the GTS system, which would be done in conjunction with Tracy and the Canadian Gas team. I would suggest that you're likely to see a power generation project or two on the Columbia assets as we continue to see the need for additional natural gas fire generation in that region.

And then we're going to continue to develop the LNG exports. If you look at the two projects that we have in service right now, Cameron LNG and then the eastern path of WBX, plus the two projects that are pending third party FIDs, we have about 3 Bcf of LNG export projects in the works right now.

And I think that there's a likelihood that you can see that number jump up to close to 4 Bcf in the not too distant future. So continued growth opportunities, and on top of all that, we're still seeing growth in the Appalachian basin.

Despite what we're hearing from the producers, the rig count is up about 10. But since the end of December to 77, production is on pace to grow out of the Appalachian basin, to the tune of about 2 to 3 Bcf by the end of the year.

All of those are bullish on what we said that additional takeaway capacity is going to be needed out of the region, perhaps sooner than we thought and our pipeline assets are uniquely situated to do just that.

Great, that's great color. Maybe just finishing on funding, you've got the 2.2 billion other kind of bucket that you laid out.

How does that number move around though from a credit metric perspective, as you think about the DRIP, which generally is probably better from a credit perspective than asset sales? And then as you think about asset sales, what's kind of the decision making process?

Is it really what sale price do you think you can get versus your long term hold value? Or is there a bias to a stronger upfront valuation, given that’s a little bit more supportive of the credit metrics during your build out?

Well, certainly DRIP is dollar for dollar equity, whereas asset sales are releasing equity and some debt capacity there. So, not every dollar is created equal.

What's in that bucket is, it's not $2.2 billion of pure equity, put it that way. We think some combination of DRIP that we have done to date and we will evaluate DRIP at the next quarter as well, depending on where we are on our projected credit metrics of being in the high-4s for 2019 and 15% FFO to debt for this year as well.

How that weighs in with the cadence of bringing our projects in service. So we're watching Sur de Texas, we're watching Napanee as to when those things come in service, now, that will influence our thinking?

We do have Coolidge preparing to close here. As I alluded to there, across the spectrum of asset sales, there were stuff at varying stages here, we won't get into the specific details of that, but again, there is stuff moving there.

In terms of sale versus hold value, it's pretty important for us that we achieve our -- at least our hold value on these assets. But we are looking at per share metrics here.

So what we're issuing stock out through a DRIP plan also informs us from that front. So kind of a long winded way of saying, we factor all this in, you should take away from the portfolio management side is with $500 billion of contracted EBITDA and some reasonable multiple on top of that, that number is substantially bigger than the $2.2 billion that's in that box right now.

So we're comfortable, we can backfill that in with portfolio management, we'll look at DRIP again in July. And we should be able to track to, we still believe we are tracking to those credit metrics for the full year 2019.

Okay. And just on that valuation though, it sounds like there is a bias to trying to sell assets that have a stronger upfront multiple?

Yeah. These are all contracted assets.

So, I mean, some of them have longer contracts and shorter contracts that weights into it. But, we're, without getting into specific EBITDA multiples on this stuff, there's a bit of a cluster there.

So I'd say that, on principle, we're probably driven more, Robert by value and multiple. And we'll look at sort of risk adjusted, sort of implied cost of capital that we can sell those assets at.

And to the extent that we can sell them at a cost of capital that we think is very attractive, that's more the drivers. As we look at shareholder value in terms of net present value, as opposed to multiple, you're in a place where that the multiple differences isn't going to make a large difference on our credit metrics at the end of the day.

So we're driven by shareholder value more than anything else.

Yeah, the other point to keep in mind here is cash taxes on these sales. So, the incident of cash taxes influence in to the thinking as well.

First question is just about Columbia Gas and just the year over year difference on what was generated in the quarter and I'm just curious if you have a breakdown handy on what amount of that was just new plants in service versus just weather conditions where you had increased flow?

Yeah. This is Stan.

Most of that is directly related to the phasing of the Columbia projects at Mountaineer and Gulf XPress going into full commercial service as of March 15. There was a minor upside associated with the cold weather that we experienced towards the end of June.

But think of that predominantly as just being the growth projects being placed in service.

Okay, that's very helpful. And then probably a question for Don, just on the 500 million of EBITDA, the contracted EBITDA that could be sales candidates.

Do you have any kind of color on just the buckets of the business that that 500 comes from?

No, we won't comment on specific assets involved in that.

And then maybe just one final question is sort of broader question. Now that you've gotten rid of a lot of the power business and you've arguably got a lot of high higher quality cash flows at this stage in time, how's the overall risk management function changed within TransCanada?

Well, as you look at the key markets in the risk management side here, I look at two specifically here. Firstly, counterparty risk, as we've sold off some contracted assets with fairly high quality counter parties, it maybe marginally, really hasn't had that pervasive impact on counterparty risk.

In terms of market risk, when you look at the assets that we've sold, the northeast power business with the whole zone J capacity pricing market, the market risk aspect of the company has dropped quite dramatically, I would say, we are 95% plus contracted EBITDA now going forward. And that's just the dissipation of that market risk has been quite pronounced.

And I think the predominant portion of that yield, so as a sub 5% of the variable EBITDA, the lion's share of that would be on the liquids side of our business. And as Paul pointed out, our objective is to try to walk down that variability and continue to narrow that amount in the proportion of that 5% that exists, power businesses is fairly small from where it used to be.

Yeah, the remaining price market, price risk is really in Alberta on our cogens and unregulated gas storage business, volumetric flows and pricing on business with the other aspect of that, as Russ mentioned.

One of my questions that’s been asked and answered. Just wanted to circle back to the Keystone XL question from before.

So just to understand this correctly, if you cross the T’s and dot the I's on all the regulatory issues, you're not concerned about crossing administrations or are you concerned and could that be a potential delay factor?

This is Paul here. The regulatory process, which is laid out in front of us is quite, is well defined.

And as always, we've been following that regulatory process to the T. Our regulatory process has been disrupted somewhat with some of the litigation that we're facing today.

The two primary pieces of litigation, the challenge to the Nebraska route approval by the Public Service commission, that rests today with the Nebraska Supreme Court and we await a decision from that quote, that is a final non-appealable decision. The second area of litigation revolves around the Presidential permit, specifically the 2017 regulatory, I'm sorry, Presidential permit with the issuance of the 2019 Presidential permit, it did two things, well, it did three things.

It superseded the 2017 permit. It mute the challenges to the 2017 permit.

And it also clarified that the cross border approval was issued by the President acting under his constitutional authority. So with the issuance of our 2019 Presidential permit, we have applied to the US District Appeals Court to vacate the District Court of Montana, the Federal District Court in Montana's judgment, including lifting the injunction.

So with the litigation behind us, it brings us back to the regulatory approvals and our construction strategy is to have those regulatory approvals all in place before we proceed. On the construction management side, the key to managing your last mile risk is to have all your regulatory approvals, have all your land, have all your resources, have all your crews, have all your material.

And once we have clarity around our ability to move forward, we will go out and secure those resources. And then we'll start construction.

And that process, that start is not yet known. And the duration will be a function of how much pre-construction planning we're able to perform between now and when we start construction, and it may overlap into the next administration.

But with regulatory approvals in hand and the rule of law, we feel comfortable constructing in that scenario.

That makes sense. And thank you for that clarity.

It's very appreciated. Maybe as a follow up and sticking on the regulatory front.

I was wondering if you can talk about the Canadian regulatory situation, Bill C-69. How do you see it potentially impacting TC Energy on an ongoing basis, if it was to go through, does it put anything at risk?

I think on the public record, I mean, we've been pretty clear on C-69 that in its current form, it's not a bill that we support and do believe that it could have significant negative impacts on our -- on both our base business and our ongoing expansion. We've been pretty specific in and detailed in our responses to the consultation process, and those are all well documented.

And we continue to work in those consultation processes to hopefully secure changes that would make that bill something that is more workable, but in its current form, we're not supportive of the bill.

If the government changes hands in October, would that make everything mute? Or do all parties support this?

Again, that I think probably similar to some of our answers on the previous questions with regards to Keystone XL, we believe that what we're doing is important that energy demand continues to grow. It will bring new supply to market on new modern infrastructure is good for the economy, job creation, energy security, national security across the board.

And I think those fundamentals transcend political parties, on both sides of the border and in all your political parties in Canada. There's no question that, everybody understands the demand for energy continues to grow, and that building modern infrastructure is the safest way to get that product from those who produce it to those who need it.

So, in between there, there's a whole bunch of noise, but those fundamentals exist and that's why we continue to be confident in our business, but on a daily basis, I mean, we have to work our way through these processes, but in our view, what we do is fundamental and that hasn't changed over the last number of years.

Just a couple of cleanup questions here. Just on the Motiva lateral.

Can you provide any additional details in terms of the size of that potential investment, whether it gets rolled into the Keystone system or cost recovery and the return is sort of standalone there?

Hi, Jeremy. It's Paul here.

The Motiva lateral, we haven't disclosed the capital costs, but it is included in our capital table under other with that 0.1, what's included in our capital table, in that bucket of $100 million of capital. So we do have a cost recovery mechanism in place.

And more importantly, what it does do, it attaches the Keystone pipeline system to the largest refinery in North America to the 630,000 barrel per day, Motiva. And this is consistent with some of our past activity over the last couple of years as we've waited on the various approvals for Keystone XL, we have extended the reach of the Keystone system into Houston, into Texas City over into Lake Charles and the value of your pipe increases as you increase the liquidity, both upstream and downstream.

So the Motiva lateral is another one -- another example of us extending the reach of the Keystone pipeline system.

That was a good lead into my follow on question, which was just around extensions of the system. And whether you can move forward with some of the extensions of Keystone, potentially before actually Keystone XL could potentially move forward with Keystone XL that is, so what other upstream and downstream options are there that you could envision ahead of KXL?

Sure. So KXL is the pipe section of the Keystone system, which runs from Hardisty, Alberta down to Steel City, Nebraska.

Our footprint includes opportunities both upstream of that as well as downstream. When I look upstream, we haven't placed plans within the intra Alberta marketplace.

We have a lot of opportunities in front of us. The Heartland Pipeline which connects the Edmonton market down to the Hardisty market is a fully permitted pipeline by the regulator.

We have Grand Rapids system, which delivers crude from the production areas down into the Edmonton market. We have the opportunity to loop that, again, that loop is fully permitted.

These opportunities, however, are waiting for clarity around egress from Alberta and with clarity around that egress from Alberta in anticipation as you will see additional investment in Alberta in the upstream, which will necessitate additional infrastructure to move that crew to the market hubs such as Edmonton and Hardisty and ultimately down pipeline such as Keystone XL. On the southern end of the system, we have seen increased production of crude oil coming out of the Permian that has necessitated infrastructure to move those volumes to the marketplace.

We saw this increase and we reacted to this increase on our market link system which is south of Cushing. We took the opportunity to increase the capacity which was running at about 450,000 barrels per day a few years ago, up to 750,000 barrels per day.

And as we see more opportunities to increase our capacity and our reach, we will look at those opportunities. Today with the increase in capacity we've achieved on market rent, we've gone to the marketplace, by way of an open season to see what sort of contract support we can get for both the existing capacity and in the event that we get into an oversubscribed position, what additional capital we might deploy on the strength of these additional contracts to increase that capacity even further.

So we're always looking for opportunities around the footprint and the nature of the Keystone system footprint runs right down the Mid-Continent gives us opportunities right along the pipeline, because that's where a lot of the emerging basins are.

And when do you expect to have sort of the results back from the open season on that market link initiative?

We launched the open season mid-April, and we typically run for about 30 days, 30, 45 days and then it typically takes anywhere from 30 to 60 days to work through credit and stuff like that. So could be about 60, 65, 70 days from now.

Hey, guys, I'm just wondering if you could comment on the NGTL maintenance program for the summer, perhaps compared to last year in terms of not so much of the financial impact, but the operational impact on customers. And if there's been any delay in kicking off the maintenance program here, just given this beautiful spring weather right now?

It’s Tracy. When we talk about a maintenance program on the NGTL system, it’s actually a combination of two things.

One is the maintenance. And the other is the work that we do on the system to expand from a capital perspective.

So we have a program this year, that is going to run a fairly significant program, but it'll run an impact about what it looked like last year, we've done I think, a good job in the last number of years of planning the maintenance program relative to the outages, relative to the capital expansion work that we're doing. And so we've seen a fairly dramatic reduction in impact on our restrictions of flow in the pipe.

So if you look at 2018 over 2017, our number of days that we restricted flow upstream James River, so your ability to get onto the pipe up there, reduced by about half, we're continuing to work to reduce that. As we go forward, we would expect this year to come in a little bit under that.

So the workload is fairly heavy, we have started on time and are on track on it. And we expect that to continue over the course of the year.

But we're continuing to work to minimize the impact of that.

And then Don, I know you can't comment on specific assets for sale, but just given the repairs that Napanee will take us into late 2019 here and I assume that Napanee represents a healthy portion of that $500 million of contracted EBITDA, safe to say that Napanee is off the table as a candidate for at least 2019.

As I mentioned earlier, we won’t comment on specific assets.

Maybe just one last one here, back to the market link open season. Paul, I know also, you can't talk specifics around where the system is today from a commercial perspective, especially pre KXL, but, perhaps you can give us a sense as to what the longer term goal is for the system from a contracted versus spot basis, just in order to maximize the risk adjusted return on the system.

Sure. Probably, again, it's a bit of a good news story, we typically land at about 80% contracted on market length.

But there's a bit of a lead like here, we increase the capacity. And given the differentials, we see the value for market is considerable.

So we typically run full with a good portion of that being spot, we go to an open season, we contract that up to derisk, and then we see the market is still looking for additional capacity. So we increase the capacity on the system, which increases really the spot component or decreases the contractual component, and then we catch up.

So, I think a good run rate estimate, given sort of the step up is probably 80%. In a scenario where we could contract it up 90 to 100, we would do that.

But again, it's a bit of a good news story. We're kind of always chasing the contracts after we increase the capacity.

We will see the results of the open season here in a couple of months. And we'll assess sort of the next step, or the next phase on capacity increase, again, depending on what sort of contractual support we achieve and where we think the market fundamentals are going.

These questions are for Stan. First, you mentioned that the potential accelerated need for Appalachian takeaway potentially.

And certainly one thing that's come up recently is really the heightened legal pushback that some of these other takeaway pipes are getting really in the Fourth Circuit, so how do you assess that risk and your exposure to that as you consider trying to figure out more takeaway solutions versus just kind of 20 existing pipes? And, are there ways for you to potentially kind of step in to help serve kind of the demand in those areas, if one or two of these pipes, kind of find it difficult to move forward ultimately?

Yeah, great question. And I would say that one thing that distinguishes many of our projects from some of our competitors is the fact that our projects tend to be in quarter expansions as opposed to Greenfield bill, which significantly de-risks some of the environmental concerns that we're dealing with.

And then secondly, keep in mind, we still have projects like our Buckeye Express, which is a project where we're doing some more with respect to reliability, integrity issues, and rather than putting a same size pipe in the ground, we're going to put a bigger size pipe in the ground. That's going to be ready to go in service in late 2020, early ‘21.

So as this additional production comes online, shippers, not necessarily going to need to wait for process to play out, we’ll have that capacity ready to go. As I pointed out, so far in 2019, we're seeing more production out of basin than we thought.

With respect to whether or not we could potentially step in and provide an alternative route for some of the other projects out there that are facing these challenges in the courts, the short answer is, we can, we have had very cursory discussions with some, but obviously those third parties would prefer to build the projects themselves. So until we get a little bit further down the road where it's more definitive as to whether or not these projects are going to go, we’ll just keep that in the discussion phase and we may be able to pull that and help them at a later date.

Easy question on Mexico and then one on the Canadian Gas pipeline business, just curious in Mexico, when do you think with the pipelines under construction, and in development, you'll be at a fully annual run rate EBITDA. Is that a 2020 timeframe?

Is that a 2021 timeframe or later?

It’s Francois. As I think we mentioned in the quarterly results, we plan on bringing Sur de Texas here into service shortly, achieving mechanical completion here later in the month of May, and then expect CSE to be declaring in service in the month of June.

On Villa de Reyes, we plan on bringing that pipeline into service in three phases. We have a northern segment, a Southern segment and then a lateral towards the west.

And we've secured interoperable contracts to CSE to be able to bring those portions into service as interconnections become available and gas is available. And as we've indicated, one or two of those portions, we expect to – our planning to put in to service here in the second half of 2019, and then the balance in the first half of 2020.

Tula, as you know, the 90 kilometer middle segment is subject to [indiscernible] obligation to conduct consultations. We've indicated that the estimated project completion now has been pushed off to the end of 2020.

We have achieved mechanical completion on the east and west segments of that pipeline, and as with Villa de Reyes, have secured interoperable contracts with the CSE to provide gas -- much needed gas supply to their power plants on those segments. So, to answer your question, based on those timelines, I think you could expect to see a full run rate by the end of 2020.

Michael, it's Don here. Just to remind everyone that we are being paid on all these pipes through force majeure payments, just the force majeure payments are not in EBITDA.

They're going to balance sheet.

Got it. Okay.

That's super helpful. Actually one small thing on the Mexico pipe business.

I noticed that some of the individual pipeline fee, the ones that are already in service and operating, actually saw a year-over-year EBITDA down in this quarter versus last year. It's really small numbers.

But I was just curious, is that kind of the trajectory we should expect going forward? Should it be relatively flat, kind of year over year?

Just curious.

For the pipelines, other than Sur de Texas, this quarter represents a pretty reasonable run rate.

Meaning run rate, it'll decline each year.

No, this will be the level going forward.

Got it. Okay, that sounds perfect.

And then finally on the Canadian gas pipeline business, I noticed that volumes were relatively flat year-over-year. Is that due to pipeline constraint issues, meaning obviously needing to continue to add capacity?

Was that a weather related issue year-over-year, a production issue, meaning just due to less associated gas potential, given the crude production cuts, just kind of curious on the volumetric side.

Michael, the system actually over the quarter and all the cold weather performed extremely well this year, and the pull out of the system on market was very strong. We hit a new peak in the intra-Alberta of some five.

So that's a good news story where we did see we expected more receipts on the system than we got and it is, as you say, that cold weather causes some problems on the production side. So we had capacity that was not utilized that on the receipt side of the business.

So, system is bigger, we moved 900 million cubic feet a day last year more to the system than we did the year before. And we're continuing to grow it, just in the cold weather months, we had some issues in bringing those volumes on.

Thanks, very much. And thanks to all of you for participating today.

We very much appreciate your participation as well as your interest in TC energy and we look forward to talking to you in the not too distant future. Thanks and have a good afternoon.