TC Energy Corp

TSX:TRP

Earnings Call Transcript 2018-Q4

[Operator]

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

[David Moneta, Vice President of Investor Relations]

Thanks very much, and good afternoon, everyone. I'd like to welcome you to TransCanada's 2018 fourth quarter conference call.With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Tracy Robinson, President of our Canadian Natural Gas Pipelines Business; Stan Chapman, President, U.S. Natural Gas Pipelines; Francois Poirier, Executive Vice President, Corporate Develop and Strategy, and President of our Mexican and Energy businesses; Paul Miller, President of Liquids Pipelines; and Glenn Menuz, Vice President and Controller. Tracy and Francois have joined us for the first time in their expanded roles following Karl Johannson's decision to retire. Both have been with TransCanada for a number of years in senior capacities.Russ and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com. It can be found in the Investors section under the heading, Events. Following their prepared remarks, we will take questions from the investment community. If you're 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 in 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 some with you following the call. Before Russ begins, I'd like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TransCanada with Canadian Securities regulators and with the U.S. Securities and Exchange Commission. And finally, during the presentation, we'll refer to measures, such as comparable earnings, comparable earnings per share, comparable earnings before interest, taxes, depreciation, and amortization or comparable EBITDA; comparable funds generated from operations, and comparable distributable cash flow. These and certain other comparable measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. These measures are used to provide you with additional information on TransCanada's operating performance, liquidity and its ability to generate funds to finance its operations.With that, I'll turn the call over to Russ.

[Russell K. Girling, President, CEO & Director]

Thank you, David, and good afternoon, everyone, and thank you very much for joining us late in the day.As highlighted earlier today in our fourth quarter news release, I am pleased to report 2018 was another very successful year for TransCanada. As outlined in that report, our CAD 100 billion portfolio of high-quality, long-life energy infrastructure assets continued to profit from strong supply and market growth in the core geographies, which our assets serve. And we continue to realize the growth expected from our industry-leading capital expansion program as we place new long-term contracted and rate-regulated assets in the service. Simply, the demand for our infrastructure remains strong, driving historically high utilization rates across our systems. That, combined with new assets entering service, resulted in record earnings and cash flow for 2018. Evidence of that can be seen in our comparable earnings of CAD 1.03 and CAD 3.86 per share for the 3 and 12 months ended December 31, 2018.During the year, we placed approximately $4 billion of new assets into service and continue to replenish our growth portfolio by adding approximately $12 billion of new regulated or contracted projects to our backlog. Those included Coastal GasLink, NGTL's 2021 and '22 expansion programs, and the Bruce Power refurbishment of Unit 6, which is expected to commence in 2020. Today, we are advancing approximately $36 billion of secured capital projects, with approximately $9 billion of those projects expected to be completed in the coming months. We are also adapting over $20 billion of projects under development, including Keystone XL, and the refurbishment of another 5 reactors of Bruce Power as a part of their long-term life extension program. In addition, we made significant progress funding our capital programs by raising approximately $9.3 billion in 2018. That included $6.2 billion for long-term debt, which was issued at very compelling rates; $2 billion of common equity that was raised through a dividend reinvestment and at the market equity programs; and another $1.1 billion that was generated from the sale of the Cartier Wind facility, and the reimbursement of approximately $470 million of pre-FID cost associated with Coastal GasLink. Collectively, those initiatives, combined with our growing internally-generated cash flow, allowed us to fund a $10.9 billion capital program in 2018. Looking forward, we expect our strong operating cash flow and financial performance to continue, and therefore comparable earnings per share expected to rise again in 2019. At the same time, our overall financial position remains solid and we believe that we're well positioned to achieve our targeted credit metrics. Don will talk about more of our funding plans in detail in just a moment. But before that, I'll expand on some recent developments, beginning with a brief overview of our fourth quarter financial results.Excluding certain specific items, comparable earnings of $946 million or $1.03 per share in the fourth quarter, which was an increase of $227 million or $0.21 per share over the same period in 2017. That equates to a 26% increase on a per share basis after recognizing the effect of common shares issued in 2017 and 2018 under our DRP program and ATM program. Comparable EBITDA increased by $550 million to approximately $2.5 billion, while comparable funds generated from operations of $1.9 billion were $431 million higher than the fourth quarter 2017. For the full year, comparable earnings of $3.86 per common share, an increase of $0.77 or 25% compared to 2017. On the year, comparable EBITDA increased by approximately $1.2 billion to $8.6 billion, while comparable funds generated from operations of $6.5 billion were $881 million higher than last year. Each of these amounts represents record results for our company and reflect the strong performance of our legacy assets, contributions from approximately $4 billion of growth projects that were completed and placed into service in 2018, and the positive impact of U.S. tax reform. Based on the strength of our financial performance and our growth outlook, TransCanada's Board of Directors today declared a quarterly dividend of $0.75 per common share, which is equivalent to $3 per share on an annual basis. That represents an 8.7% increase over last year, and is the 19th consecutive year that our board has raised the dividend. Since 2000, we have maintained consistently strong coverage ratios with our dividend on average representing a payout of approximately 80% of comparable earnings and 40% of internally generated cash flow, leaving us with financial capacity to continue to invest in our core businesses. Don again will provide more detail on the fourth quarter financial results and the 2019 outlook in just a few moments. But before he does, a few comments on our 5 operating businesses.First in Canadian Natural Gas Pipelines. Customer demand for access to our systems remains strong, and we continue to work with industry on options to connect growing Western Canadian Gas to markets across North America. Evidence of that demand for our services can be seen in the volumes we transported across our network. Our NGTL system delivered an average of 12.3 billion cubic feet a day in 2018, an increase of about 8% compared to the 11.4 billion cubic feet a day that we transported in 2017. Similarly, on the Canadian Mainline, total deliveries averaged 5.2 billion cubic feet a day in 2018, an 18% increase over the 4.4 billion cubic feet a day we moved in 2017. Over the past year, we also announced commercial support for NGTL's 2021 and 2022 expansion programs. With those announcements, we are now advancing an $8.6 billion expansion program on NGTL that will add approximately 3.2 billion cubic feet a day of incremental delivery capacity to the system by the end of 2022.In December, we also secured 625 million cubic feet a day of new natural gas transportation contracts from the Canadian Mainline, following the successful completion of the North Bay Junction long-term fixed price open season. The incremental volumes under these long-term contracts will reach markets in Ontario, Québec, New Brunswick, Nova Scotia and the northeast United States. Finally, in the Canadian natural gas pipeline business, we continued to actively work with LNG Canada on our Coastal GasLink pipeline project following the positive final investment decision on the LNG terminal in Kitimat, British Columbia. The $6.2 billion project will have an initial capacity of approximately 2.1 billion cubic feet a day, with a potential expansion capacity of up to 5 billion cubic feet a day. All of the necessary regulatory permits have been received to allow us to proceed with construction activities, and Coastal GasLink has signed long-term agreements with all 20 elected First Nations along the pipeline right away. These agreements total hundreds of millions of dollars in direct lending over the life of the project. Funds that these nations can use to build stronger communities and address their local priorities. In addition to that direct funding, we have also conditionally awarded $620 million in contract work on the project in Northern British Columbia to indigenous businesses and anticipate another $400 million in contract and employment opportunities for both indigenous communities and local communities along the pipeline route during construction. In addition, we have also expect to provide significant employment opportunities for First Nations along the pipeline right of way. Construction on the project has commenced, and all 5 LNG Canada joint venture partners have elected to make cash payments throughout the construction period, with respect to the carrying charges on all of our cost incurred. Most of the construction spend on Coastal GasLink is expected to occur in the 2021 -- or 2020 and 2021 period, and we are exploring joint venture partners and project financing alternatives for the project. As a result, we believe our funding needs for the project are very manageable, particularly considering the 4-year construction time frame for the project.Moving to our U.S. Natural Gas Pipelines, where the demand for our services has also reached record levels. As we've previously highlighted, our broad network in the United States has historically served approximately 25% of U.S. daily demand. More recently, winter deliveries have averaged about 24.5 billion cubic feet a day, and the cold temperatures that gripped much of North America in late January here and early February, led to peak day delivery on our system, which is a record of 33 billion cubic feet a day on January 30, of 2019. In addition to moving record volumes on our existing systems, during the fourth quarter and early into this year, we also continued to advance USD 6.7 billion of expansion projects including Columbia's WB, Mountaineer, and Gulf XPress projects. The $900 million WB XPress project entered service in the fourth quarter, and approximately 45% of the USD 3.2 billion Mountaineer XPress project capacity was placed into service in mid-January. Today approximately 60% of the Mountaineer XPress project is in service, and earlier this week, we received FERC authorization to place 60% of the USD $600 million Gulf XPress capacity in service. The balance of Mountaineer and Gulf XPress capacity is expected to enter service in February and March.At the same time, we continue to identify other opportunities across our broader U.S. natural gas pipeline portfolio to connect growing Marcellus and Western Canadian supply to growing markets. An example of that is our Louisiana XPress project, which was sanctioned in late 2018. It rolled out approximately 800 million cubic feet a day of capacity and connects supply to the Gulf Coast LNG export markets through the addition of 3 Greenfield compressor stations along our Columbia Gulf system. The project is expected to cost USD 400 million, and is anticipated to be in-service in 2022. Turning to Mexico, where we continued to advance construction on 3 pipelines at a total cost of about USD 3 billion. Offshore construction of Sur de Texas is complete, and the project continues to progress toward an anticipated in-service date in the early second quarter of 2019. The Villa de Reyes project and the Tula project are anticipated to be in service in 2019 and 2020 respectively. While our Mexican projects have faced some delays, the CFE has approved the payment of fixed capacity charges on our pipelines in accordance with their respective 25-year transportation service agreements.Turning now to our liquids business, which produced very strong results, again, in the fourth quarter of 2018. Keystone, which is underpinned by long-haul take-or-pay contracts for 555,000 barrels per day, essentially ran at a capacity in -- at capacity in 2018, moving an average of 590,000 barrels a day. On the southern portion of our system or the U.S. Gulf Coast segment, capacity was increased throughout 2018, reaching approximately 700,000 barrels a day by year-end. As capacity increased through the year, we maintain near-full utilization rates, averaging approximately 700,000 barrels a day in the fourth quarter. In addition, we continue to benefit from higher contribution from liquids marketing activities, largely due to improved volumes and margins because of favorable market conditions. That is expected to continue into 2019. During the quarter, we also continued to advance Keystone XL. In Nebraska, as you know, we received approval of a route in that state. However, that decision has been challenged. We expect the Nebraska Supreme Court could reach a decision in the first quarter of 2019 with respect to that appeal of the Nebraska Public Service Commission's approval of the route. We continue to work collaboratively with landowners in Nebraska to obtain the necessary easements for the approved route. To date, we have obtained negotiated easements for approximately 80% of the route in the state, and we expect that percentage to continue to rise. We also continue to participate, together with U.S. Department of Justice, in lawsuits commenced in Montana to defend the legal challenges to the U.S. presidential permit and the exhaustive environmental assessments that support the U.S. President's actions. We have now secured commercial support for all available capacity on the Keystone XL system, and we have commenced certain preconstruction activities. We remain committed to building this project, and we will continue to carefully and methodically obtain the regulatory and legal approvals necessary before we advance the project to construction. Turning to our energy business. Construction on Napanee is essentially complete, and commissioning activities are well underway. We expect the facility to be placed into service in the second quarter. We also -- work also continues on the Bruce Power life extension project, with significant investments to extend the operating life of the facility to 2064, scheduled to begin in 2020 and continue through 2033. In late September, Bruce Power submitted its final cost and schedule estimate for the unit 6 major component replacement project to the Ontario ISO. The ISO has verified the estimates, and as a result, the project is scheduled to begin in early 2020. We expect to invest approximately $2.2 billion in Bruce Power's Unit 2 MCR Program as well as the ongoing asset management program through 2023, when Unit 6 refurbishment is expected to be completed. Bruce Power's contract price of approximately $68 per megawatt hour is expected to increase to approximately $75 per megawatt hour on April 1, 2019, to reflect the capital to be invested under these programs as well as normal annual inflation adjustments.Finally, in energy, in October, we closed the sale of our interests in Cartier Wind for approximately $630 million. And in December, we entered into an agreement to sell our Coolidge Generating Station in Arizona for approximately USD 465 million or CAD 620 million. That sale is expected to close in mid-2019. The sale of these facilities allows us to surface significant value for mature assets that represented less than 15% of our generating capacity and redeploy that capital into our $36 billion secured capital program. Thereby, reducing our need for external capital, including common equity.In addition, with the addition of Coastal GasLink, the NGTL 2021 program and the '22 programs, and the Bruce Power unit 6 refurbishment, we are now advancing $36 billion of secured growth projects that are expected to enter service by 2023. It includes approximately $5 billion of maintenance capital, 85% of which is related to our regulated natural gas pipelines, and therefore, is expected to be added to rate base and generate a return on and of capital, identical to what we realized on expansion projects.We've invested $13 billion into that program to date with approximately $9 billion of those projects expected to enter service in the next few months. These projects, to be completed in the near term, include Columbia's Mountaineer and Gulf XPress projects, the Sur de Texas Natural Gas Pipeline in Mexico, and the Napanee gas-fired power plant in Ontario. Notably, all of the projects in our portfolio are all underpinned by long-term contracts or cost-to-service regulation, giving us a high degree of visibility to earnings and cash flow growth that will be generated as they enter service between now and 2023.This highlights the significant growth in EBITDA that is expected as we continue to advance our secured capital program. As you can see from this chart, comparable EBITDA, which has risen from approximately $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 annual growth rate of approximately 9% over the 6-year period. 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, we are advancing $20 billion of projects currently under development. Any one of those projects could further enhance our growth profile as well as our strong competitive position.Based on our confidence in our growth programs, we continue to grow the dividend at an average annual rate -- we expect to continue to grow the dividend at an average annual rate of 8% to 10% through 2021. As always, it's been our practice that growth in our dividend is expected to be supported by sustainable growth in earnings and cash flow per share as well as strong distributable cash flow coverage ratios. In summary, I'll leave you with the following key messages: over the past 20 years, we have transformed ourselves into a leading North American energy infrastructure company, with a very 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 continues to grow. Today, our $100 billion asset portfolio generates approximately $8.6 billion of annual EBITDA, with approximately 95% of that coming from regulated business models for long-term contracted assets. Looking forward, we have 5 significant platforms for growth: Canadian, U.S., and Mexico Natural Gas Pipelines; liquids pipelines; and energy. And just as we have done since 2000, as we advance our $36 billion secured capital program, we expect to deliver continuous growth in earnings, cash flow and dividends per share. In addition, we have more than $20 billion of projects that are in advanced stages of development, and we expect numerous other growth opportunities to emanate from our extensive critical asset footprint. We have a history of prudently funding our capital programs, and we are on track to deliver -- to continue to delever our balance sheet, post the 2016 acquisition of Columbia and achieve our targeted credit metrics.That concludes my prepared remarks, and I'll turn the call over to Don, who'll provide you with more details on the fourth quarter financial results and our 2019 outlook. Don?

[Donald R. Marchand, Executive VP & CFO]

Thanks, Russ, and good afternoon, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares is $1.1 billion or $1.19 per share in the fourth quarter of 2018 compared to $861 million or $0.98 per share for the same period in 2017. Fourth quarter results included $143 million after-tax gain related to the sale of our interests in the Cartier Wind power facilities; $115 million deferred income tax recovery from an MLP regulatory liability write-off, resulting from our 2018 FERC actions; a $52 million recovery of deferred income taxes as a result of finalizing the impact of the U.S. tax reform; a $27 million income tax recovery related to the sale of our U.S. Northeast power generation assets; and $25 million of after-tax income realized on Bison contract terminations. These positives were partially offset by $140 million after-tax impairment charge for Bison, and a $15 million after-tax goodwill impairment charge for Tuscarora. The amounts for Bison and Tuscarora, which are held by TC PipeLines, LP, reflect our proportionate share of these impairments net of noncontrolling interests. Lastly, fourth quarter results included an after-tax net loss of $7 million related to the wind down of our U.S. Northeast power marketing contracts. Fourth quarter 2017 results also include several specific items as outlined on this slide, and discussed in the fourth quarter 2018 financial highlights release. All of these specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings.Excluding specific items, comparable earnings of $946 million or $1.03 per share in fourth quarter 2018 were $227 million or $0.21 per share higher year-over-year. This equates to a 26% increase on a per share basis, after giving effect to the dilutive impact to common shares issued under our dividend reinvestment plan and at-the-market program. These, along with other funding activities do, however, have us on track to return to long-term targeted leverage metrics following the 2016 Columbia acquisition and continuing record capital program. Our positive results reflect broad operational strength and solid cash generation, particularly in Canadian and U.S. Natural Gas pipelines, along with Liquids pipelines. Turning to our business segment results on Slide 20. Beginning this quarter, our financial disclosure will include enhanced information around comparable EBITDA and its key drivers period-over-period.In the fourth quarter, comparable EBITDA from our 5 operating segments was approximately $2.5 billion, a $550 million or 29% increase from 2017. Canadian Natural Gas Pipelines' comparable EBITDA of $818 million was $249 million higher than for the same period last year. The increase is primarily due to the recovery of higher depreciation as a result of increased rates approved in both the NGTL 2018-2019 settlement, and the Mainline NEB 2018 decision as well as higher flow-through taxes and incentive earnings. As a result of the timing of the NEB 2018 decision, the full year impact of higher depreciation, flow-through taxes, and incentive earnings on the Mainline was reflected in the fourth quarter.The decision approved all elements of our application, including our cost and volume forecast, a higher depreciation rate, and continued pricing discretion, with the exception of treatment of the long-term adjustment account, or LTAA balance, which is now to be amortized over 2018 to 2020. I would note that for Canadian Natural Gas Pipelines, changes in depreciation and financial charges and income taxes impact comparable EBITDA, but do not have a significant effect on net income as they are almost entirely recovered in revenues on a flow-through basis. Net income for the Canadian Mainline increased $11 million year-over-year, primarily due to higher incentive earnings recorded in the period. Net income for the NGTL system increased $18 million compared to fourth quarter 2017 as a result of a higher average investment base, continued system expansions, and increased OM&A incentive earnings.The U.S. Natural Gas Pipelines comparable EBITDA of USD 613 million or CAD 812 million in the quarter increased by USD 138 million or CAD 208 million compared to the same period in 2017, mainly due to increased contributions from Columbia Gulf projects placed in service, additional contract sales on ANR and Great Lakes and increased earnings from the amortization of net regulatory liabilities recognized following the U.S. tax reform, partially offset by a reduction in certain rates on Columbia Gas as a result of U.S. tax reform.Mexico Natural Gas Pipeline's comparable EBITDA of USD 115 million or CAD 152 million was USD 24 million or CAD 36 million above fourth quarter 2017 as a result of changes in timing of revenue recognition, equity earnings from our investment in the Sur de Texas pipeline, which records AFUDC during construction, net of interest on an interaffiliate loan from TransCanada, along with incremental earnings [ McRae ] tariff increase. The interest expense on the Sur de Texas interaffiliate loan is fully offset in interest income and other in the Corporate segment. Liquids pipelines' comparable EBITDA rose by $137 million to $538 million in fourth quarter 2018, driven by increased volumes on the Keystone pipeline system, a higher contribution from liquids marketing activities due to improved volumes and margins, incremental earnings from Intra-Alberta pipelines, which began operations in the second half of 2017, and lower business development costs as a result of capitalized and Keystone XL expenditures in 2018. Energy comparable EBITDA decreased by $47 million year-over-year to $167 million due to lower earnings from Bruce Power, driven by reduced volumes from higher outage days, decreased Western and Eastern power results due to the sales of Cartier Wind in fourth quarter 2018 and Ontario Solar Assets in fourth quarter 2017, and a lower contribution from Natural Gas Storage, primarily due to pipeline constraints in Alberta, limiting our ability to access the storage facilities causing narrower realized price spreads. This was partially offset by higher Western power realized margins on improved generating volumes. For all our businesses with U.S. dollar-denominated income, including U.S. Natural Gas Pipelines, Mexico Natural Gas Pipelines and parts of liquids pipelines and energy, fourth quarter 2018 Canadian dollar translated EBITDA benefited from a stronger U.S. dollar compared to the same period in 2017. This positive foreign-exchange impact at the business unit level was largely offset by higher translated interest expense on U.S. dollar-denominated debt and realized hedging losses on derivatives used to manage our net exposure to foreign exchange rate flow fluctuations reported in comparable interest income and other.As a reminder of our approach to managing foreign exchange exposure, our U.S. dollar-denominated revenue streams are partially hedged by interests on U.S. dollar-denominated debt. We then actively manage the residual exposure on a rolling 1-year forward basis.Now turning to the other income statement items on Slide 21. Depreciation and amortization of $681 million increased $165 million versus fourth quarter 2017, largely due to the increased depreciation rates on the Mainline and NGTL, with amounts fully recovered as reflected in the increase in EBITDA described earlier as well as new facilities entering service across our businesses.Interest expense included in comparable earnings of $603 million for fourth quarter 2018 was $62 million higher year-over-year following net debt -- new debt issuances net of maturities, higher levels of short-term borrowing, and increased translated U.S. dollar-denominated interest due to a stronger U.S. dollar, partially offset by higher capitalized interest primarily due to ongoing construction of Napanee and the recommencement of capitalization of Keystone XL development costs in 2018. AFUDC increased $21 million for the 3 months ended December 31, 2018, compared to the same period in 2017, due to higher capital expenditures on NGTL, continued investment in Mexico projects and additional investment in and higher AFUDC rates on Columbia growth projects.Comparable interest income and other decreased by $45 million in the fourth quarter versus 2017, primarily as a result of realized hedging losses on foreign exchange management in 2018 compared to realized gains in 2017, partially offset by higher interest income related to the interaffiliate loan receivable from the Sur de Texas joint venture, offsetting the corresponding interest expense recorded in comparable EBITDA. Even though they fully offset on consolidation, GAAP requires that we report the interest income and expense elements of this loan separately in the financial statements.Income tax expense included in comparable earnings was $268 million in fourth quarter 2018 compared to $234 million for the same period last year. A $34 million increase was mainly on account of higher comparable earnings before income taxes and increased flow-through income taxes on Canadian rate-regulated pipelines, with such amounts fully recovered as reflected in the increase in EBITDA discussed previously, partially offset by reduced tax rates as a result of the U.S. tax reform.Operable net income attributable to noncontrolling interest of $86 million in the fourth quarter increased by $37 million relative to the same period last year, mostly due to higher comparable earnings in TC PipeLines, LP. And finally, preferred share dividends were comparable to fourth quarter 2017.Now moving to cash flow and distributable cash flow on Slide 22. Comparable funds generated from operations of approximately $1.9 billion in the fourth quarter reflects an increase of $431 million year-over-year, driven primarily by higher comparable earnings, recovery of greater depreciation for NGTL and the full year impact of recovering increased depreciation on the Mainline. Comparable distributable cash flow reflecting only nonrecoverable maintenance capital expenditures was approximately $1.7 billion in the quarter or $1.89 per share compared to $1.3 billion or $1.45 per share in the fourth quarter of 2017, resulting in a coverage ratio of 2.7x. As highlighted previously, we believe that including only nonrecoverable maintenance capital in the calculation of distributable cash flow conveys the best depiction of cash available for reinvestment or distribution to shareholders, as our ability to recover rate regulated and liquids maintenance capital expenditures through current or future tolls effectively nears that of growth capital.Now turning to Slide 23. During the fourth quarter, we invested approximately $3.4 billion in our capital program and successfully funded it through strong and growing internally generated cash flow, along with several diverse financing levers. In October, we raised USD 1.4 billion through our senior unsecured notes offering comprised of USD 1 billion of 30-year notes at a fixed rate of 5.1% and USD 400 million of 10-year notes at a fixed rate of 4.25%. Also in October, we closed the sale of the Cartier Wind power generation assets for approximately $630 million, resulting in a gain of $143 million after tax, recorded in the fourth quarter. In November, the 5 parties to LNG Canada reimbursed us for their share of pre-FID development costs associated with the Coastal GasLink project, totaling $470 million. Recently, in January, all 5 parties elected to make cash payments throughout the CGL construction period, with respect to carry charges on costs incurred. In December, we entered into an agreement to sell our Coolidge Generating Station for approximately USD 465 million or CAD 620 million, subject to timing of the close and related adjustments. The sale will result in an estimated $50 million after-tax gain to be recognized upon closing of the transaction, which is expected to occur in mid-2019. Our dividend reinvestment plan, or DRP, continues to provide incremental subordinated capital in support of our growth and credit metrics. In the fourth quarter, the participation rate amongst common shareholders was approximately 34%, representing $215 million of dividend reinvestment. For full year 2018, the participation rate was approximately 35%, resulting in $870 million of common equity at a 2% discount. Funding activity not just from the fourth quarter but throughout 2018 continues to highlight the depth and diversity of the financial options available to us, allowing us to prudently fund our capital program and achieve targeted credit metrics.Now turning to Slide 24. This graphic highlights our forecasted sources and uses of funds from 2019 through 2021. Starting in the left column, the total funding requirement over the next 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. The increase relative to Investor Day largely reflects the announced Louisiana XPress project, as well as slight capital increases and modest project development costs. Also as a reminder, we are pursuing joint venture partners and asset level financing towards funding the $6.2 billion Coastal GasLink project. The expenditure will be spread over approximately 4 years, with a bulk of the spend in 2020 and 2021. For purposes of our funding program outlook through 2021, and consistent with what we conveyed at Investor Day in November, we assume we maintain a 25% interest in Coastal GasLink, which is reflected in our capital requirements.The second column highlights aggregate sources including approximately $21 billion of internally generated cash flow, approximately $500 million of proceeds from our dividend reinvestment plan for the January 2019 dividend payment, and the dividend declared today to be paid at the end of April, as well as approximately $620 million of proceeds from the announced sale of Coolidge Generating Station expected to close in mid-2019.That leaves the capital markets requirement of approximately $6.9 billion in the far right column. We expect to issue approximately $3 billion of incremental debt through 2021 within the constraints of our targeted credit metrics of debt-to-EBITDA in the high fours range, and minimum FFO-to-debt of 15%. Additionally, we expect to issue $1.5 billion of hybrids, maintaining these securities along with preferred shares at about 15% of our capital structure. The remaining $2.4 billion, as illustrated by the purple box, will be comprised of activities such as incremental DRP proceeds beyond the dividend most recently declared, and portfolio management activities. DRP remains a quarter-to-quarter decision, influenced by financial performance against targeted metrics, along with the cadence of getting growth projects into service and the timing of asset sales. With the deal for Coolidge now signed, we still have additional assets that generate approximately $500 million of annual contracted EBITDA that have been identified as potential viable portfolio management candidates. Applying a reasonable multiple, the associated proceeds would notably exceed our residual funding requirement. As in the past, while we will not preannounce targeted asset sales, you should not take silence as inactivity as illustrated with our most recently announced transactions for Coolidge, Cartier Wind, and Ontario Solar. In summary, while our external funding needs remain sizable, they are eminently achievable in the context of the multiple financing levers available and are clear, accretive, and credit support of these proceeds. Everything is evaluated on a per-share basis, and further share 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 $36 billion capital program. And ultimately, our goal is to revert to our historical, self-funding model.Now turning to Slide 25. Next, I'd like to spend a moment on our 2019 comparable earnings outlook. Additional information is contained in our 2018 annual management's discussion and analysis, which is being filed on SEDAR today, and available on our website. Canadian Natural Gas Pipelines earnings in 2019 should be higher than 2018, mainly due to the continued growth on the -- in the NGTL's systems investment base. We expect earnings in the Mainline to be slightly lower due to decreased incentive earnings. The NEB 2018 decision to accelerate the amortization of the LTAA over the 2018 to 2020 period effectively reduces tolls, revenues, and income taxes in those years, but has no significant impact on net income.U.S. Natural Gas Pipelines earnings are expected to be higher in 2019 than in 2018, due to, among other factors, increased revenues following the completion of expansion projects on Columbia Gas and Columbia Gulf in 2018 and 2019.In Mexico Natural Gas Pipelines, we expect 2019 earnings to be higher year-over-year, primarily due to the incremental contribution from the Sur de Texas pipeline, which is projected to be in service in early second quarter. In liquids, our 2019 earnings are expected to be similar to 2018, primarily as a result of significant take-or-pay contracts and continued high demand for capacity on our assets. Our 2019 comparable earnings for the Energy segment are expected to be higher than 2018, primarily due to an increased contribution from Bruce Power, largely driven by an increased contract price to reflect the capital to be invested in the Unit 6 MCR and AM programs. The average Bruce plant availability percentage in 2019 is projected to be in the high 80s range, comparable to 2018. Incremental earnings and the completion of Napanee are also expected to drive higher energy results, partially offset by the sale of our interest in the Cartier Wind facilities in 2018 and the anticipated sale of Coolidge in mid-'19. Comparable earnings per share in 2019 will also be impacted by the dilutive impact of common shares issued in 2018 under our DRP and ATM program, and expected to reap issuance in 2019, along with higher interest expense as a result of debt financings to help fund our capital program and lower capitalized interest on projects placed in-service. For our effective income tax rate, excluding Canadian rate regulated pipelines, where income taxes are a flow-through item, nevertheless quite variable, along with equity AFUDC income in U.S. and Mexico Natural Gas Pipelines, we expect our full year 2019 effective rate to be in the mid- to high teens. Finally as part of 2019 outlook, I would like to note that we have very limited interest rate foreign exchange or commodity price variability inherent in our diversified portfolio. In summary comparable earnings in 2019 on a per-share basis are expected to be higher than 2018. In terms of capital spending, our plan is to invest approximately $8 billion in 2019 on growth projects, maintenance capital, and contributions to equity investments. The majority of the anticipated 2019 capital program is attributable to expenditures on Coastal GasLink, NGTL, Columbia Gas modernization 2, and the Bruce Power life extension program, along with normal course maintenance capital expenditures of approximately $1.7 billion, of which, approximately 85% is recoverable.The 2019 capital program estimate includes $1 billion for the Coastal GasLink project, reflecting 100% of the capital spend. As previously messaged, we are seeking joint venture partners for up to 75% of the project.Lastly, turning to Slide 26. In closing, I offer the following comments. Our solid, across-the-board financial and operational results in the fourth quarter highlight our diversified low-risk business strategy and reflect the strong performance of both our blue chip legacy portfolio, along with the contribution of equally high-quality assets from our ongoing capital program. Today we are advancing a $36 billion suite of secured projects, and have 5 distinct platforms for future growth in Canadian, U.S. and Mexico Natural Gas Pipelines, liquids pipelines, and Energy. Our overall financial position remains strong. We remain well positioned to fund our secured capital program through resilient and growing internally-generated cash flow, and strong access to capital markets on compelling terms, supplemented further by capital recycling. We will continue to make all funding decisions based on per share metrics. Our portfolio of critical energy infrastructure is poised to generate significant growth and high-quality long-life earnings and cash flow for our shareholders. That is expected to support annual dividend growth of 8% to 10% through 2021. Success in adding to our growth portfolio in the coming years could augment or extend the company's dividend growth outlook further. That's the end of my prepared remarks. I'll now turn the call back over to David for the Q&A.

[David Moneta, Vice President of Investor Relations]

Thanks, Don. Just a reminder, before I turn it over to the conference coordinator for questions from the investment community, we do ask that you limit yourself to 2 questions. If you have any additional questions, please reenter the queue. Now with that, I'll turn it over to the coordinator.

[Operator]

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

[Linda Ezergailis, Research Analyst]

Just a question with respect to your Canadian Natural Gas Pipelines. Can you give us a sense now of where the pinch points are in the path to market? And how might the next round of debottlenecking and potential expansions unfold?

[Tracy A. Robinson]

We have, as you know, a very strong supply base in the WCSB. In fact, we have -- our issue is not supplier issuance market. And we're working as hard as we can to address the egress issues we have -- in 2018, about 900 million cubic feet a day more moving through the system than they did in 2017, And we have -- as you heard Russ talk about, $8.6 billion going into incremental egress off the NGTL system over the course -- between now and 2022. So that's into intra-basin demand. That's on to the Mainline, through these gates. It's down to the GTN on West Path. And beyond that, it's going to be another 2.1 Bcf a day once we have Coastal GasLink pipeline built to the LNG facility on the West Coast. So lots of work going on right now. And we're always in discussion with our shippers around what the next path to market is. We recently signed an agreement with Nauticol for 300 million cubic feet a day of supply into a new methanol facility that they're contemplating here in Grand Prairie. So those conversations continue all the time. And it's an important part of our dialogue. We need more market.

[Linda Ezergailis, Research Analyst]

And maybe just as a follow-up. Looking south of the border, I'm wondering what -- where the discussions are in terms of expansions on the U.S. natural gas pipeline system there?

[Stanley Graham Chapman]

So Linda, this is Stan. I'll start, and Tracy could add in if she wants to. Think of the U.S. pipes as a big catcher's mitt. GTN, for example, fully subscribed effective come 2020. We do have the ability to expand that pipe to the tune of about 0.5 Bcf a day. We think it's competitive rates. Moving forward across the system east, Great Lakes, has about another Bcf of capacity that could take additional volumes from the Mainline. And then, you've probably seen some of the success we've had on the East Coast with respect to expansions of our Portland natural gas transmission system. That's being expended to the tune of about 60%, 65% more capacity than it has today. So think of the U.S. as a big catcher's mitt, ready to receive all the growing production from Canada.

[Linda Ezergailis, Research Analyst]

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

[Stanley Graham Chapman]

Yes. Absolutely. Late last year, we announced our Louisiana XPress project, a $400 million expansion to serve and establish the LNG export terminal. Just today, we sanctioned another project called our Grand Chenier XPress project, a $225 million opportunity to feed a new LNG export terminal player. So in the aggregate, you can think of LNG experts as growing to 10 Bcf a day over the next 5 to 10 years. With the positions we have at Grand Chenier, at Louisiana XPress, and with our Cameron project, that's about 3 Bcf of capacity to serve these terminals or about 30% of the market going forward.

[Operator]

Our next question is from Robert Kwan from RBC Capital Markets.

[Robert Michael Kwan, Analyst]

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

[Tracy A. Robinson]

Robert, yes, there's lots of interest in doing that and in reaching any number of markets. Eastern Canada down to the Northeast U.S., down on -- or across our U.S. system as well as growing interest in the prospect of access through LNG and global markets off the East Coast as well. I would say that it's mixed stability with the balance sheets in -- with across the producer community. In the basin, I would say that they're stepping into it in bits and pieces, but we're also seeing market come to the basin to pick up gas. Most recently, in our North Bay Junction open season, we saw market and the LBCs in the East. In the Northeast U.S, we saw petrochemical in the East and we saw the maritimes buy transport back to Empress in order to pick up the basin's gas. So it's a combination of the producers willing to step out, and the market willing to come back into the basin to get transport.

[Robert Michael Kwan, Analyst]

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

[Tracy A. Robinson]

Yes. There is. I think, between the last 2 LTFP deals we've done, we've demonstrated that the basin's gas can get into Eastern Canada, Northeast U.S. now into the maritimes competitively. And so those deals are in the money, they're working, and we hope to see more of that.

[Robert Michael Kwan, Analyst]

Okay. Perfect. And maybe I'll just finish the question for Don. Looking at U.S. tax reform, you've got the statement of no material impact expected for the pipelines. I'm just wondering though, do you have any thoughts here on the anti-hybrid rules? Whether that's U.S. legislation or that's generally? And what you see the potential impact here being?

[Donald R. Marchand, Executive VP & CFO]

Yes. Yes. For context, these are proposed regulations that provide more definition to U.S. tax reform. These were released right near the end of 2018. They're quite complex and comprehensive. So we're currently assessing the potential impact on our financing structures. It's a bit of a challenge as these aren't expected to be in final form until mid-2019. Probably the best way to look at tax reform, there's 3 elements to interest deductibility in the states. The first 2 came last year. One, was an absolute limitation, 30% of EBITDA was your limit on interest deductibility with a carve-out for regulated utilities, which the vast majority of our assets, of our businesses, actually fall under that exemption. They introduced a minimum tax called the BEATS, base erosion anti-avoidance (sic) [ anti-abuse ] tax, that was also restrictive of how much interest you can deduct there. What they've done now is introduced, basically, a characterization test, if you will, as to the characterizing funding structures, and how interest is channeled back through various corporate forms. So what we're doing right now is we're just assessing that. We could see some transactional impact -- transitional tax cost impact here until the final regulations are in place. But we're hopeful they won't have a material impact on our long-term cost to financing a U.S. operation. So it's a bit of a stay-tuned right now. We're just indicating that there's a lot of moving parts here right now, and we're still interpreting that.

[Robert Michael Kwan, Analyst]

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

[Donald R. Marchand, Executive VP & CFO]

Exactly. Yes. It would -- directionally, it would be a modest negative, but we don't know if that will manifest itself or how big that would be. And it may very well just be transitional for a short period of time here. So at this point, it's just, again, flagging that this is out there. And we're just looking at it, and it's going to take a healthy chunk of 2019 to figure out what, if any impact, there is from it.

[Operator]

Our next question is from Rob Hope from Scotiabank.

[Robert Hope, Analyst]

I want to transition over to Keystone XL. There is a number of processes in play. I just want to get a sense of what your expected kind of paths forward are for the Montana process as well as kind of what are the key dates to ensure that you hit that 2019 summer construction window?

[Paul E. Miller]

This is Paul Miller here. Starting with Montana, we continue to work the Montana District Court decision. We had some success in having the injunction narrowed, but we are pursuing a path to have the decision reversed with the U.S. Department of Justice. And at this point, we are waiting on a decision on that appeal from the District Court. The other court challenge we have is in Nebraska Supreme Court, on the PSC approval. That argument was heard back in late 2018, and we're waiting for the decision from the Supreme Court as well. We're also pursuing a couple of other State Department permits, one being the Bureau of Land Management and the Army Corps of Engineers. And what's happening there is, in the Montana court decision, the judge identified some deficiencies with the SEIS. And so State Department is going through additional work on our SEIS. We anticipate that they will be -- complete their work and -- through the comment period here by, let's call it, second quarter. Following the issuance of the SEIS, the state -- sorry, the Bureau of Land Management and the Army Corps of Engineers will be in a position to issue their decisions and their permits. In the meantime, we continue to work some preconstruction activity that is allowed under the injunction. But before we spend any material dollars, we will have to have resolution of these matters behind us.

[Robert Hope, Analyst]

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

[Paul E. Miller]

Our intent is to start construction in 2019, and we have a 2-year construction window. But we also have an optimal construction program, which takes advantage of seasonality. It takes advantage of various construction windows that are available to us. There will come a point where because of the desire to pursue this optimal structure, we will lose 2019. We're not at that point yet. We continue to work these various hurdles, again, with a goal to achieving starting in 2019. But it's uncertain at this time when we will have these various legal and regulatory hurdles behind us.

[Operator]

Our next question is from Jeremy Tonet from JPMorgan.

[Jeremy Bryan Tonet, Senior Analyst]

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

[Donald R. Marchand, Executive VP & CFO]

Jeremy, it's Don. So the -- from an accounting perspective, what we're looking at here is lower tolls, and that will also lower taxes. So that should -- would modestly result in a modestly lower EBITDA. But from a net income basis, that's, from an accounting perspective, fully offset in below the line in terms of lower income tax expense. So we wouldn't expect it, from an accounting perspective, to have any major impacts. So a modest negative, we'll call it on EBITDA, modest being the key word there and neutral to earnings. From a geography standpoint, the deferrals that were collected are actually sitting in deferred amounts and other in investing activities, not operating activities. So this shouldn't have a major impact on cash flow. The drawdown of that balance will, again, just be within investing activities. A bit arcane, but I'm not sure if that helps.

[Jeremy Bryan Tonet, Senior Analyst]

That's helpful. And just when we look at the Liquids segment, it seems like it's quite a nice step up quarter-over-quarter with regards to the Keystone, in addition to the oil pipeline business development. I think you were expecting it to be kind of flattish year-over-year there. I was just wondering, is that kind of -- you've locked in some attractive activity earlier in the year, and that would dissipate over the course of the year? Or just trying to better understand the ratability of what's happening in the segment because it seems like Keystone XL is kind of flattish up until this quarter.

[Paul E. Miller]

Jeremy, Paul again. I think when you look at the various components of the Liquids Pipelines business, we're going to see 2019 look very similar to 2018 across all the components. The contracted segment will be relatively flat. When I look at the spot that we've generated on both Keystone as well as Marketlink and I take a look at the current and future differentials, I would anticipate that we would see similar levels in 2019. And on the marketing affiliate, same. When I take a look at the capacity that they do hold, the positions they hold in the markets in which they operate, and the current and future differentials, I would anticipate seeing similar results to them as well. So year-over-year, you're going to see 2019 very similar to 2018.

[Operator]

Our next question is from Ben Pham from BMO.

[Benjamin Pham, Analyst]

I want to go back to the Canadian Mainline. Just looking at the year-over-year EBITDA increase of $200 million. It looks like half of that is the depreciation that you've highlighted. And then, there's $11 million of incentive earnings. Just wondering what's driving the balance of the increase, just also given the rate base is also down 9% or so.

[Tracy A. Robinson]

Ben, you have to look at -- on the quarter, all -- the full impact for the year on the decision on 2018, 2020, tolls is registered in the fourth quarter. So you're seeing a lot of activity there. Don't get distracted by how big some of that looks. From incentive earning perspective, there's nothing big that's moving around. If you look at the run rate at the end of the year, you can use that kind of as a proxy of what the run rate looks like going forward. Does that make sense?

[Donald R. Marchand, Executive VP & CFO]

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

[David Moneta, Vice President of Investor Relations]

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

[Benjamin Pham, Analyst]

Okay. That's great. And then, my second question on the commentary around self-funding, you inserted that language at Investor Day. I'm wondering what do you think you need to see to get comfort in moving towards self-funding turn out to DRP? And have you thought about just how your growth rate would look under that scenario?

[Donald R. Marchand, Executive VP & CFO]

Yes. Sure. The -- so DRP right now, as I mentioned in my remarks, is really a quarter-to-quarter decision, and it's driven by a couple of things here. One is operational performance and how we're tracking towards our target credit metrics, and getting a comfort level that we will be in the high 4s and minimum 15% FFO to debt for 2019. Important inputs into that are the cadence of our projects coming into service here. So we're watching that very closely. As noted, we expect the next couple of months to see $9 billion of assets fully placed in service here. That represents north of $1 billion of EBITDA that is all contracted and regulated. And as well, asset sales. We've got Coolidge announced. We've got other processes at varying stages. We're not going to give a whole lot of definition to that, but we're -- if we can add more asset sales to truncate the DRP program, we will do that.

[Benjamin Pham, Analyst]

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

[Donald R. Marchand, Executive VP & CFO]

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

[Russell K. Girling, President, CEO & Director]

Yes. I mean, as we've talked about before, I mean, when you sort of ex all of the current funding that we've got on and the lag between the AFUDC earnings and cash flow, that's somewhat muddies the water. When we run our model of reinvesting our free cash flow and the debt capacity that comes from retained earnings, if we reinvest that into projects that return about 8% after tax, which on average has kind of been our portfolio over the last 20 years. We generated growth rate in the 7% to 8% range. As we said at Investor Day, like over the last 20 years, we've invested some $85 billion into our core assets, and that's been our -- a little bit higher than our cash flow and earnings, haven't had too many bumps in the road. And we've driven a growth rate in earnings per share, cash flow per share and dividends per share at around 7%. That's what I think sort of the true run rate of the company is. I would cite anomalous events, like making large acquisitions like Columbia, where we had the opportunity to over-lever ourselves for a period of time. But at the same time, build out expansion projects that had a greater return than the 8%. That led to that 8% to 10% through 2021. As we look out beyond, I mean, my challenge to the team here as always, we have to try to beat that 7% to 8%. But I think, if you look at our history over the last 20 years, that's what we've done. And for the last few years, we've been closer to the 8%, 9%, 10%. But long run, I would expect the number in that sort of 7% to 8% range, very similar to what we've done for the last 20 years.

[Operator]

Our next question is from Dennis Coleman from Bank of America Merrill Lynch.

[Dennis Paul Coleman]

A couple for me, please. I guess if we can start, there's been quite a lot of news in the north -- from the Northeast U.S. gas producers. A lot of budget reductions, still strong production growth near term, but I wonder if you might talk about that and what you're hearing from them and how that impacts potential growth maybe out the curve a little bit.

[Stanley Graham Chapman]

This is Stan. I think what you're seeing is producers living within their means. And they have announced that they're cutting back some of the capital programs, which very well could mean a reduction in supply in the short term. I'll tell you, on our systems, when we put our Leach XPress project into service, which was 1.5 Bcf a day, we saw very strong flows, 1.3, 1.4 Bcf a day. Our WB XPress project went into service this fall, 1.3 Bcf and we're seeing consistent flows in the 1.1 Bcf a day range. So high usage there. Mountaineer XPress, we've had about between 1.1 and 1.5 Bcf a day capacity in service over the past month, but we've only seen nominations in the 500,000 to 800,000 a day range. So I think big picture, what this tells me is that the producers are waiting for a little bit of a recovery in prices. This very well could be the beginning of an overbuild to an extent in the U.S., where we have more capacity than we have production in the short term. However, longer term as we look out over the next 10 years, and see the potential for Marcellus to grow from 30, 31 Bcf today to 40 Bcf, we think that there's going to be a need for additional export capacity out of the region.

[Dennis Paul Coleman]

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

[Donald R. Marchand, Executive VP & CFO]

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

[Dennis Paul Coleman]

So later this year? Can I just pursue? Is that we'll know something second half? Or will it be first half?

[Donald R. Marchand, Executive VP & CFO]

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

[Russell K. Girling, President, CEO & Director]

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

[Operator]

Our next question is from Robert Catellier from CIBC Capital Markets.

[Robert Catellier]

I just wanted to follow up on that line of questioning, specifically, confirm my understanding that the target of a high 4 leverage ratio, it includes the sale of a joint venture interest in Coastal GasLink. And so if that's the case, if there is a delay to the process because of the jurisdictional challenge or otherwise, do you still intend to target the 4% -- the 4x leverage? And what would be your avenue to get there?

[Donald R. Marchand, Executive VP & CFO]

Yes. It's Don here, again. Yes. We will absolutely target that high-4s leverage ratio. We -- from bringing in a JV partner here, I think it's the wait beyond this year, which is not our base case nor our expectation. We're talking several hundred million dollars of spend this year that we would fully absorb. So it's not something material in the context of $100 billion balance sheet.

[Robert Catellier]

Okay. And then, just there's been a lot of media, I guess, recently on the -- from the Mexican president on the force majeure payments being made on the pipelines, among other things. What's your take on that? And what's your strategy to deal with that situation?

[Francois Lionel Poirier]

Robert, it's Francois speaking. First, I think -- I'll provide a little bit of context here. As we talked about our investment and our capital outlay in Mexico in aggregate for the 7 projects, those -- between those in operation and those under construction, we've been guiding towards an aggregate EBITDA in the range of USD 575 million or so. And with the 4 pipelines in operation being Tamazunchale, Mazatlán, Guadalajara, and Topolobampo, and once we bring Sur de Texas into service here early in the second quarter, we'll be approaching USD 500 million of that USD 575 million. So in terms of putting a context around the magnitude of the situation, I thought that was appropriate. We've made some comments here publicly earlier this week around the fact that the CFE pipeline contracts were the result of a public bidding process under Mexican law, was transparent and in accordance with industry standards. And in fact, we were pleased to see the administration here reaffirm that they'll abide by their obligations under the contracts. It's actually correct. Our contracts include force majeure provisions that apply when either we or the CFE are prevented from fulfilling our obligations due to circumstances that are beyond our control. But I would say that since the completion of our projects, it's clearly in the mutual interest of the CFE and TransCanada. Frankly, we welcome the opportunity to work with the government and with CFE to find solutions to the issues that are preventing their completion. These projects supply much-needed natural gas to the country, to supply gas for gas-fired generation, which shall result in significantly lower electricity cost and lower pollution. And so that alignment of interests gives us confidence that when we engage and we are engaging with the CFE, that those will be productive conversations.

[Donald R. Marchand, Executive VP & CFO]

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

[Operator]

Our next question is from Shneur Gershuni from UBS.

[Shneur Z. Gershuni]

Just a quick clarification to the wonderful detail you gave on the last question. Are you basically saying that there is only $75 million at risk once you get to the middle of 2019?

[Francois Lionel Poirier]

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

[Shneur Z. Gershuni]

Okay. Perfect. As a follow-up question here. In terms of your targets to get to the high 4s in terms of leverage you've talked about, [indiscernible] bills, Mexico, and obviously, Coastal GasLink have been on the list. Does the jurisdiction discussion at the NEB impact your ability to monetize Coastal GasLink in the same thing with respect to these contract negotiations from Mexico? Like do these things have to be settled before a buyer will actually take a stake? Or is there an interest despite these uncertainties out there?

[Donald R. Marchand, Executive VP & CFO]

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

[Operator]

[Operator Instructions] Next question is from Michael Lapides of Goldman Sachs.

[Michael Jay Lapides, Vice President]

And by the way, to Karl, I don't know if he's listening in, congrats on the retirement. Real quick. Just on the Coastal GasLink, one of the things I wanted to make sure I understood was the timeline. Because it seems like you're doing a lot of the work -- a little bit of work in 2019, a lot of the work in 2020 and 2021. But if I remember when Shell and the other owners started talking about the in-service date, I thought they kind of hinted at kind of late 2023, sometime in 2024. So -- and didn't really kind of hammer down an exact date, but it wasn't before the end -- towards the end of 2023. Just why have the pipe in service so much earlier or so much before the LNG facility will be around?

[Tracy A. Robinson]

It's Tracy. Yes. We do have -- we have agreement with LNG Canada around certain timelines to have the pipe in the ground. We'll take some time after that for commissioning and getting it in-service. And all that timeline should line up with roughly when LNG Canada will have their facility ready. So all this timeline works with the kind of commitment that we've made to LNG Canada.

[Michael Jay Lapides, Vice President]

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

[Tracy A. Robinson]

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

[Michael Jay Lapides, Vice President]

Got it. And one last thing, speaking of LNG, there's been obviously some talk about LNG on the Eastern Coast of Canada. Just curious, there's one or 2 projects. They're very early stage. How you guys are thinking about whether that's kind of realistic from a siting, permitting, contracting standpoint?

[Tracy A. Robinson]

Well, I would tell you that we were doubters early on, but these -- there's a number of proponents that are looking at Eastern LNG. And they continue to make progress. We're in discussions with all of them, and they're all, I would say, at various stages of the development of supply, getting pipe capacity, a position in LNG facility and finding market. They're all in various stages of that, but some of them are very interesting. And certainly, they're all approaching it with a significant amount of intent. So we're watching that carefully. And we have not yet signed any agreements with any of them, but we are in dialogue with all of them.

[Operator]

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

[David Moneta, Vice President of Investor Relations]

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

[Operator]

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