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Good afternoon, ladies and gentlemen. Welcome to the TC Energy Corporation 2019 First 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.
Great. 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, Liquids Pipelines; Francois Poirier, Executive Vice President, Corporate Development and Strategy, and President, Mexico and Power and 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 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'd 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 2 questions. If you have additional questions, please reenter the queue. Also, we ask that you focus your questions on our industry, our corporate strategy, recent developments and key elements of our financial performance. If you have detailed questions relating to some of our smaller operations or your detailed financial models, Duane and I would be pleased to discuss them with you following the call.Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TC Energy with Canadian Securities regulators and with the U.S. Securities and Exchange Commission. And finally, during this presentation, we'll refer to measures, such as comparable earnings, comparable earnings per share, comparable earnings before interest, taxes, depreciation, and amortization or 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'll 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 3 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 3 countries: Canada, 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 continue to perform from strong supply-demand fundamentals in the core geographies that we serve. And we continue to realize on the growth expected from our industry-leading capital expansion program as we've placed 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 3 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 continued to advance over $20 billion of projects under development, including Keystone XL and the refurbishment of 5 additional reactors at Bruce Power as part of their long-term Life Extension Program. In addition, we continue to make progress funding our capital program 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 USD 465 million by midyear 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 financial results and 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, the Board of Directors today declared the 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 amount 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 the financial capacity to continue to invest in our businesses. Next, I'd like to make a few comments about our 5 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 to markets across North America. Evidence of the 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 volumes 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 GasLink 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 preconstruction activities continue at many locations along the pipeline route. Moving to our natural gas -- our U.S. Natural Gas Pipelines where the demand for our services reached record levels. As highlighted previously, our broad network has historically served about 25% of U.S. demand on a daily basis. More recently, winter deliveries averaged 24.4 billion cubic feet a day, and the cold temperatures that gripped much of North America 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 U.S. systems during the first quarter, we continued to advance $5.8 billion of secured expansion projects. Columbia's Mountaineer XPress along with the Gulf XPress projects were phased into service over the first quarter of 2019. At the same time, we continued to identify new opportunities across our broader U.S. Natural Gas Pipelines 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 ANR 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 2 phases over the 2021 and 2022 period at a cost of about USD 200 million. Turning to Mexico where we're advancing construction on 3 pipelines at a total cost of 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 phased 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-Villa de Reyes project to be placed in-service when the facilities are complete and gas is available. Turning to our liquids 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 U.S. Gulf Coast segment, capacity was increased throughout 2018 reaching approximately 700,000 barrels a day by year-end. As capacity increased, we maintained near full utilization rates in the fourth quarter and again into the first quarter of 2019. In addition, we continue to benefit from higher contribution from liquids marketing activities, largely due to improved 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's 630,000 barrel a day refinery in Port Arthur. That connection is targeted to be operational in the second quarter of 2020. Finally, in the liquids business, during the first quarter, we continued to advance Keystone XL. In late March, the U.S. 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 U.S. 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, which 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 U.S. Department of Justice in lawsuits commenced in Montana to defend legal challenges to the U.S. presidential permit and the exhaustive environmental assessments that support the U.S. 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 now 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 reported segmented results. In Power and Storage, we experienced equipment failure on the $1.7 billion Napanee project while progressing commissioning 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 (sic) [ 2019 ] 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 6 program as well as ongoing asset -- the ongoing asset management program through 2023, when Unit 6 refurbishment is complete. Bruce Power's contracted price of approximately $68 per megawatt hour increased to approximately $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 an agreement to sell our Coolidge Generating Station in Arizona for approximately $465 million or CAD 620 million. The sale is expected to close mid-2019. This sale allows us to surface significant value for a mature asset 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 secured 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 base and generate a return on enough capital identical to that which we realized on expansion projects. We have 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 include the $2.8 billion of the NGTL expansions as well as the Sur de Texas Natural Gas Pipeline in Mexico and the Napanee gas-fired power plant 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 secured 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 6-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 of projects currently under development. Anyone 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, it has been our practice that growth in dividends 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 5 significant platforms for growth, Canadian, U.S. and Mexican Gas Pipelines, Liquids Pipelines and Power and Storage. Just as we have done since 2000, as we advance 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 emanate from our existing extensive critical asset 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 the 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.
Okay. 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 runoff of our U.S. Northeast power marketing contracts. These specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Comparable earnings in the first quarter rose by $123 million to $987 million or $1.07 per share compared to $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 in 2018 and 2019 and at the market program in 2018. 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 15. In the first quarter, comparable EBITDA from our 5 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 Pipelines 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 at 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. 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, flow-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 and 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 3 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. U.S. Natural Gas Pipelines comparable EBITDA of USD 730 million or CAD 972 million increased by USD 95 million or CAD 168 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 Pipelines comparable EBITDA of USD 110 million or CAD 146 million decreased USD 17 million or CAD 14 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 interaffiliate loan, which amount is fully offset in interest income and other in the corporate segment. Liquids pipelines 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 cost 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 investments supporting employee post-retirement benefits and lower volumes and revenue resulting from higher outage days. 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 Power and Storage, Canadian dollar translated EBITDA was positively impacted by a stronger U.S. dollar versus the first quarter of 2018. This was largely offset by higher translated interest expense on U.S. dollar-denominated debt and realized hedging losses reported in comparable interest income and other. As our U.S. 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 U.S. dollar-denominated debt. The residual balance is actively managed on a rolling 1-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 U.S. dollar, partially offset by the sale of our interest in the Cartier Wind power facilities in 2018, and the cessation of depreciation on our Coolidge Generating Station upon classification as held for sale at December 31, 2018. Interest expense included in 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 U.S. dollar on translation of U.S. dollar-denominated interests, partially offset by higher capitalized interest related to Napanee and Keystone XL. AFUDC rose by $34 million to $139 million for the 3 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 in our NGTL System while an increase in U.S. dollar-denominated AFUDC was driven by continued investment in U.S. 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 interaffiliate 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 noncontrolling interest increased by $7 million for the 3 months ended March 31, 2019, mostly due to higher earnings in TC PipeLines, LP, and the impact of a stronger U.S. 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 of 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 from both the Canadian Mainline and NGTL System. Distributable cash flow reflecting only nonrecoverable 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 2.3x. 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 proximally 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 USD 465 million or CAD 620 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 our forecasted sources and uses of funds through 2021. Starting in the left column, the gross funding requirement over the next 3 years is projected to be $29 billion comprised of dividend and noncontrolling 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 towards funding the $6.2 billion Coastal GasLink project. The expenditure will be spread over approximately 4 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 GasLink, 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 leaves the 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 our targeted credit metrics of debt to EBITDA in the 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, while we generally do not preannounce targeted asset sales, silence 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 discrete 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 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 are advancing a $30 billion suite of secured projects and have 5 distinct platforms for future growth in Canadian, U.S., 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 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.
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 2 questions. And if you have any additional questions, please reenter the queue. With that, I'll turn it back to the conference coordinator.
[Operator Instructions] And the first question is from Jeremy Tonet at JPMorgan.
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 would 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 about some sizable packages 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 FID decision. In the meantime, we had -- 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 along the various litigation that's out in front of us. And once resolved, we'll make a determination on 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 are 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're in the public domain but -- and I wouldn't necessarily tie anything underway right now to KXL directly. We look at portfolio management more holistically as 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 get 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 in 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 until it would be in service. Certainly, portfolio management continues in a normal course here. KXL 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. You could look to 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, in all of the above strategy on the funding side.
That's helpful. And just turning to the liquids side, it seems like you guys have exceeded our estimate once again there. And so I was just 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 were able to kind of capture spreads out there. I'm 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 $0.005. The variability you see potentially is on the Marketlink 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. Investor Day last year, I indicated that we would be targeting about mid-7,000 barrel per day range on the southern end, and we achieved that in the 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 Marketlink. And as is our practice, as we increase this capacity, we look to lock it down by 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, approximately equal, you saw similar results. Going forward, Q2 with what we have locked down and where the market's 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 may be $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 $0.01 decline in Q4. But we will go and take advantage of those opportunities in the marketplace as they present themselves.
The next question is from Linda Ezergailis of TD Securities.
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 TC PipeLines fits into TransCanada over the long term? And how do you continuously assess the merits of it to remaining an MLP in your strategy?
Linda, it's Don here. Yes, currently these are core assets, but also note that versus peers in the industry, our LP is a fairly small portion of a $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 use of capital at this time. Drop downs 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 move 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 enhanced the service offerings you can provide to 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 Mainline rate design and services evolve as well over time? Is this part of a bigger grander plan? And maybe if you can just give us an update on how you're thinking about that?
Sure. Thank you. The application that went in on the NGTL was on rate design, and it had 2 purposes really. We restructured the design to more accurately reflect how volume flow now on the NGTL System. So there were some changes in tolls and services related to that. And secondly, it took on this issue of how we toll the North Montney Mainline. You will recall that we received some feedback from the Board that a full roll in on North Montney they felt wasn't appropriate. We continue to believe it is appropriate, but we took the guidance from the Board of -- with surcharge. So part of that application is a surcharge on the North Montney Mainline. So that is the piece that's going to go to a hearing from the Board. It's very complex. It's very large. It spans 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 dialogue through a hearing, and they have scheduled that hearing now. As it relates to the Mainline, we are in process of a very interesting dialogue 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 tolls and services a little bit differently on that line. So that dialogue is 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 basin's volumes to market. We have a basin that's prolific, got some great well, very competitively priced gas, and we want to be helpful on getting that into market.
Thank you. And is this something that we'll 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 Investor Day, maybe a little bit later depending on -- I mean, it's a very complex topic and lots of different options as we think about the full kind of flexibility that we have before us as an industry. So later this year perhaps.
The next question is from Rob Hope at Scotiabank.
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?
Rob, it's Paul here. I think the best way to describe it is our focus is managing the legal and the 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 the industry, and it's a very important project for North America. And the construction start and the duration may overlap into the next administration, we don't know. But ultimately, we will move forward with 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 will ultimately be able to construct this pipeline in normal course.
All right. And then just switching over to the Coastal GasLink. When you look at the schedule there, are there any key chokepoints 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 preconstruction activities on numerous points along that pipe path, primarily clearing and setting up the camps. We'll be into the heart of construction laying pipe next year in 2020. And as of now -- I mean, it's very early on in 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 path and are -- remain in constant dialogue with all of our partners, including the First Nations, along the right-of-way. So we are where we need to be right now.
The next question is from Robert Catellier at CIBC Capital Markets.
I think I'll follow up on the Coastal GasLink. As you 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?
Rob, 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 and we continue to believe that this project is properly positioned within the provincial jurisdiction of British Colombia. 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 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 the -- 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 does look like it goes through another administration. Is there -- are there any other risk-sharing mechanisms with shippers that are under consideration?
Well, Rob, we do have today risk-sharing mechanisms with shippers on the development cost, 50-50. But as we assess the last-mile risk, again, 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 is, we continue to identify and mitigate those risks, but ultimately, it's going to be at FID when we make that ultimate call on how good of a job we've done.
Okay. I guess what I'm getting at here is, is there a -- have you socialized these with the 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?
Robert, it's Russ. That's getting ahead of where we are. Now first of all, we have to determine whether we can get the permits and solve the legal issues that are in front of us today. At that point, we can assess what the risks are. And at that point, we can assess how we're going to finance it, mitigate any risk that's 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 and the United States, and refiners, and as well, you would note that there's the 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.
The next question is from Robert Kwan at RBC Capital Markets.
Probably a question for Stan. Just turning to the U.S. 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 into what you had in Investor Day in terms of the 8-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 table and the projects that are under development that you're referring to. Our 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 U.S., point to growth in terms of increased production, they point to LNG growth and they point to growth in power gen. And as we sit right now, we have projects in various stages of origination across virtually all of our pipes in the U.S. I would expect that perhaps as early as later this year, you're going to see another supply push project, the GTN 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 2 on the Columbia assets, as we continue to see the need for additional natural gas power generation in that region, and then we're going to continue to develop LNG exports. If you look at the 2 projects that we have in service right now, Cameron LNG and then the eastern path of WB X, plus the 2 projects that are pending, third-party FIDs, we have about that 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 of 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. Our 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 kind of a decision-making process? Is it really what sale price 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?
Good question. 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 then we will evaluate DRIP in 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, and that will influence our thinking. We do have Coolidge preparing to close here. As I alluded to, across the spectrum of asset sales there were -- we have 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 whole value, it's pretty important for us that we achieve our -- at least our whole value on these assets, but we are looking at per-share metrics here. So what we're issuing stock at through a DRIP plan also informs us on that front. Kind of a long way of saying, we factor all this in. What you should take away from the portfolio management side is with $500 million 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'll be 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?
Yes, these are all contracted assets. So I mean, some of them have longer contracts and shorter contracts that weighs into it. But we're -- without getting into specific EBITDA multiples on this stuff, there's a bit of cluster there so.
I would say that on principle we're probably driven more, Robert, by value than 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 what the driver is. We look at shareholder value in terms of net present value as opposed to multiple. You're in a place where 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.
Yes, the other point to keep in mind here is cash taxes on these sales. So the incident of cash taxes influences the thinking as well.
The next question is from Andrew Kuske at Crédit Suisse.
My first question is just about Columbia Gas and just the year-over-year difference on what was generated in the quarter? I'm just curious if you have a breakdown handy on what amount of that was just new plant in service versus just weather conditions where you had increased flow?
Yes, 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 January, 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 million comes from?
No, we won't comment on specific assets involved in that.
Okay. And then maybe just one final question, just sort of broader question. Now that you've gotten rid of a lot of the power business and you are giving out a lot of higher quality cash flows at this stage in time, how has the overall risk management function changed within TransCanada?
Well, as you look at the key buckets in the risk management side here, I look at 2 specifically here. First, the counterparty risk, as we've sold off some contracted assets with fairly high quality counterparties, it may be moved marginally, really hasn't had that pervasive of an impact on counterparty risk. In terms of market risk, when you look at the assets that we've sold, the merchant northeast power business with the whole Zone J capacity pricing market, the market risk aspects, the company has dropped quite dramatically, I would say. We are 95% plus contracted EBITDA now going forward, and then that's just -- the dissipation of that market risk has been quite pronounced.
Yes, I think the predominant portion of that yield, so as a sub-5% of variable EBITDA, the lion's share of that would be yield on the liquid side of our business. And as Paul pointed out, our objective is to try to lock down that variability and continue to narrow that amount. The portion of that 5% that exists in our power business is fairly small from where it used to be.
Yes, the remaining price -- market price risk is really in Alberta on our cogens and unregulated gas storage business, volumetric flows and pricing on impulse business would be the other aspect of that, as Russ mentioned.
The next question is from Shneur Gershuni at UBS.
One of my questions have 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 Ts and dot the Is in all the regulatory issues, you're not concerned about crossing administrations? Or are you concerned? And could that be a potential delay factor?
Not concerned. The regulatory -- sorry, 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 2 primary pieces of litigation, the challenge on the Nebraska route approval by the Public Service Commission, that rests today with the Nebraska Supreme Court and we await a decision from that court. 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 2 things -- or it did 3 things. It superseded the 2017 permit, it rendered moot 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 that 2019 presidential permit, we have applied to the U.S. District Appeals Court to vacate the District Court of Montana, the Federal District Court of Montana's judgment, including lifting the injunction. So with that 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 preconstruction plan 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. 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 a significant negative impacts on our -- on both our base business and our ongoing expansion. We've been pretty specific 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's 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 moot? Or do all parties support this?
Again, that -- I think probably similar to 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, they'll bring new supply to market on new modern infrastructure is good for 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 political parties in Canada, there's no question that everybody understands 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 though, 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 business, I mean, we have to work away through these processes. But in our view, what we do is fundamental and that hasn't changed over the last number of years.
The next question is from Jeremy Rosenfield at Industrial Alliance.
Just a couple of clean-up questions here. Just on 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?
Jeremy, it's Paul here. The Motiva lateral, we haven't disclosed the capital cost, but it is included in our capital table under other, with that point 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, but more importantly what it does do, it attaches the Keystone pipeline system to the largest refinery in North America to be 630,000 barrels per day Motiva refinery. 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 Steele City, Nebraska. Our footprint includes opportunities both upstream of that as well as downstream. When I look upstream, we have in place plans within the inter-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 the 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, anticipation is you'll see additional investment in Alberta in the upstream, which will necessitate additional infrastructure to move that crude to the market hubs such as Edmonton and Hardisty and ultimately down pipeline, such as Keystone and 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 Marketlink system, which is south of Cushing. We took the opportunity to increase the capacity, which was running at above 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 increasing capacity we've achieved on Marketlink, 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, which 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 a sort of the results back from the open season on that Marketlink issue?
We launched the open season mid-April and we typically run for about 30 days, 30 to 45 days. And then it typically takes anywhere from 30 to 60 days to work through credits and stuff like that. So it could be about 60, 65, 70 days from now.
The next question is from Patrick Kenny at National Bank.
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 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 out west right now?
Patrick, it's Tracy. We do -- when we talk about a maintenance program on the NGTL System, it's actually a combination of 2 things. One is the maintenance and the other is the work that we do in the system to expand from a capital perspective. So we have a program this year that is going to run. It's a fairly significant program, but it will run and 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 the ability to get onto the pipe up there, produced 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.
Okay, that's great. And then, Don, I know you can't comment on specific assets for sale, but just given the repairs at 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 specifically comment on specific assets.
Fair enough. Maybe just one last one here, back to the Marketlink 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. Well, probably -- again, it's a bit of a good news story. We typically plan it about 80% contracted on Marketlink, but there's a bit of a lead leg here. We increased the capacity, and given the differentials, we see the value from Marketlink 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 of capacity increase, again depending on what sort of contractual support we achieve and where we think the market fundamentals are going.
The next question is from Alex Kania at Wolfe Research.
These questions are for Stan. First, you'd mentioned that there's an 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 4 circuits. So how do you assess that risk and your financial exposure to that as you consider trying to figure out more takeaway solutions? Or is this 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 some of -- if 1 or 2 of these pipes kind of find it difficult to move forward ultimately?
Yes. 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 corridor expansions as opposed to greenfield builds which significantly derisks some of the environmental concerns that we're dealing with. And then secondly, keep in mind, we still have projects like our Buckeye XPress, which is a project where we're doing some work 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 initial production comes online, shippers are not necessarily going to need to wait for a FERC 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 the 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 discussion with some, but obviously those third parties will 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 something that we may be able to pull out to help them at a later date.
The next question is from Michael Lapides at Goldman Sachs.
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 full annual run rate EBITDA? Is that a 2020 time frame? Is that a 2021 time frame? Or later?
Michael, 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 CFE to be declaring in service in the month of June. On Villa de Reyes, we plan on bringing that pipeline into service in 3 phases. We have a northern segment, a southern segment and then a lateral towards the west. And we've secured interruptible contracts with CFE to be able to bring those portions into service as interconnections become available and gas is available. And as we've indicated, 1 or 2 of those portions we expect to planning to put into service here in the second half of 2019 and then the balance in the first half of 2020. Tula, the -- pardon me, Tuxpan-Tula, as you know, the 90-kilometer middle segment is subject to Chenier's obligation to conduct consultations. We have indicated that the estimated project completion now have 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, we have secured interruptible contracts with the CFE to provide gas, much-needed gas supply to their power plants on those segments. So to answer your question, based on those time lines, 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. It's 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 pipelines, the ones that are already in service and operating, actually saw 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 trajectory we should expect going forward? Should it be relatively flat kind of year-over-year? Just curious.
Michael, it's Glenn. Yes, for the pipelines other than Sur de Texas, this quarter represents a pretty reasonable run rate.
Meaning run rate, it will decline each year?
No. As in 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 potentially given the crude production cuts? Just kind of curious on the volumetric side.
Michael, the system actually over the quarter in 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 just over 75. So that's a good news story. Where we did see, we expected more receipts onto 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 on the receipt side of the business. So the 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. It's just in the cold weather months, we had some issues in bringing those volumes on.
Ladies and gentlemen, this concludes the question-and-answer session. If there are any further questions, please contact TC Energy Investor Relations. I will now turn the call back over to Mr. Moneta. Please go ahead, Mr. Moneta.
Thanks very much, and thanks to all of you for participating today. We very much appreciate your 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.
Thank you. Ladies and gentlemen, your conference has now ended. All callers are asked to hang up their lines at this time, and thank you for joining today's call.