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Good morning, ladies and gentlemen. Welcome to the TransCanada Corporation 2018 Third Quarter Results Conference Call.I will now like to turn the meeting over to Mr. David Moneta, Vice President, Investor Relations. Please go ahead, Mr. Moneta.
Thanks very much, and good morning, everyone. I'd like to welcome you to TransCanada's 2018 Third Quarter Conference Call. With me today are Russ Girling, President and Chief Executive Officer; Don Marchand, Executive Vice President and Chief Financial Officer; Karl Johannson, President of Canada and Mexico Natural Gas Pipelines and Energy; Stan Chapman, President, U.S. Natural Gas Pipelines; Paul Miller, President of our Liquids Pipelines business; and Glenn Menuz, Vice President and Controller. Russ and Don will begin today with some opening comments on our financial results and certain other company developments.A copy of the slide presentation that will accompany their remarks is available on our website at transcanada.com. It can be found in the Investor section under the heading Events.Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Grady Semmens following this call, and he would be happy to address your questions. In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to 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 TransCanada with Canadian securities regulators and with the U.S. Securities Exchange Commission.And finally, I'd also point out that during this presentation, we'll refer to measures such as comparable earnings, comparable earnings per share, comparable earnings before interest, taxes, depreciation and amortization or comparable EBITDA, comparable funds generated from operations and comparable distributable cash flow. These and certain other comparable measures are considered to be non-GAAP measures; as a result, they may not be comparable to similar measures presented by other entities. They are used to provide you with additional information on TransCanada's operating performance, liquidity and our ability to generate funds to finance our operations.With that, I'll turn the call over to Russ.
Thank you, David. And good morning, everyone, and thank you very much for joining us today. As highlighted in our quarterly report to shareholders released earlier today, we're very pleased to announce another quarter of strong results, which are expected to contribute to record financial performance in 2018.As outlined in the report, our CAD 94 billion portfolio of high-quality energy infrastructure assets continue to profit from strong underlying market fundamentals, and we are realizing the growth expected from our secured capital expansion program. Evidence of this can be seen in our comparable earnings of CAD 1 and CAD 2.82 per share for the 3 and 9 months ended September 30, 2018, which supports our Board of Director's decision in February of this year to increase our quarterly common share dividend to CAD 0.69 per share. That equates to CAD 2.76 per share on an annual basis and represents a 10.4% increase over the dividend we paid in 2017.During the quarter, we also continued to advance CAD 36 billion of secured capital projects which now includes Coastal GasLink, NGTL's 2022 expansion and Bruce Power's refurbishment of Unit 6, which is expected to commence in 2020.Approximately CAD 10 billion of these projects are expected to enter service by early 2019. Those include the NGTL system expansions, Columbia's Mountaineer, WB and Gulf XPress projects, a Sur de Texas natural gas pipeline in Mexico and the Napanee gas-fired power plant in Ontario. We also continue to advance over CAD 20 billion of projects under development, including Keystone XL and the refurbishment of another 5 reactors at Bruce as part of their long-term life extension program.And finally, we have made progress on funding our capital program by raising approximately CAD 9.1 billion this year. That includes CAD 6.1 billion of long-term debt which was issued at very compelling rates, CAD 2 billion of common equity that has been raised through our dividend reinvestment program and the at-the-market equity program. And approximately CAD 1 billion in total from the sale of our 62% interest in the Cartier Wind facility and the reimbursement of approximately CAD 400 million of predevelopment costs associated with Coastal GasLink under the provisions in our agreements with LNG Canada's joint venture participants.Collectively, these initiatives combined with our growing internally generated cash flow means that are 2018 funding program is now complete.Looking forward, we expect our strong operating and financial performance to continue and, therefore, comparable earnings on a per share basis in the fourth quarter of 2018 are expected to be consistent with the results that we've achieved in the first 9 months of this year.At the same time, our overall financial position remains strong and we believe we are well-positioned to achieve our targeted credit metrics without the need for discrete common equity to fund our CAD 36 billion secured capital program.Don will talk about our funding activity in more detail in just a moment. But before that, I'll expand on some recent developments beginning with a brief review of our third quarter financial results.Excluding certain specific items, comparable earnings were at CAD 902 million or CAD 1 per share, an increase of CAD 288 million or CAD 0.30 per share over the third quarter of 2017. That equates to a 43% increase on a per share basis after recognizing the effect of common shares issued in 2017 and 2018 under our DRP and ATM programs.Comparable EBITDA increased CAD 389 million to approximately CAD 2.1 billion, while comparable funds generated from operations of CAD 1.6 billion were CAD 255 million higher than the third quarter of 2017. These amounts reflect the strong performance of our legacy assets and contributions from approximately CAD 7 billion of growth projects that were completed and placed into service over the last 12 months, and the positive impact of U.S. tax reform.On a year-to-date basis, comparable earnings were CAD 2.82 per share, an increase of CAD 0.55 or 24% compared to the first 9 months of 2017. Comparable EBITDA increased CAD 636 million to approximately CAD 6.1 billion, while comparable funds generated from operations of CAD 4.6 billion were CAD 450 million higher than last year.Again, Don will provide more detail on the third quarter financial results in just a few moments. But before he does, I'd like to make a few comments on recent developments in each of our business segments beginning with Natural Gas Pipelines.First in the Canadian Natural Gas Pipeline business, yesterday we announced the commercial support for NGTL's 2022 expansion program that will see as invest approximately CAD 1.5 billion over the 2021-'22 timeframe. The project is underpinned by approximately 1.1 Bcf a day of new firm service contracts with terms that range from 8 to 20 years. The program, which is subject to NEB approval is expected to be complete by April 2022.With today's announcements, we are now advancing CAD 9.1 billion to commercially secured growth projects on the NGTL system over the 2018 to 2022 period. Looking forward, customer demand for access to our systems remains strong and we continue to work with industry on options to connect growing Western Canadian gas supply to markets across North America. And as I've said before, that could include the potential restoration of dormant capacity on the Canadian Mainline.At the same time, we are actively working with LNG Canada and our Coastal GasLink pipeline project following the positive final investment decision on their LNG terminal in Kitimat B.C. The CAD 6.2 billion project will have an initial capacity of approximately 2.1 Bcf a day, with the potential expansion capacity of up to 5 Bcf a day. All of the necessary regulatory permits have been received to allow us to proceed with construction activities on, and the Coastal GasLink has signed project and community agreements with all 20 elected indigenous spans along the pipeline route, confirming the strong support from the indigenous communities across British Columbia for the project.Construction is expected to begin in early 2019, with a planned in-service date of 2023. Most of the construction spend is expected to occur in the 2020 and 2021 period. And we are exploring joint venture partners and project financing options for the project. As a result, we believe that our funding needs for this project are very manageable, particularly considering the 4-year construction time horizon of the project.Moving to our U.S. Natural Gas Pipelines. During the third quarter, we advanced USD 6.1 billion of expansion projects, including the Columbia's Mountaineer, WB and Gulf XPress projects. All 3 are expected to enter service by the end of 2018 at a combined investment of approximately USD 4.5 billion.At the same time, we continue to look at other opportunities across our broader U.S. Natural Gas Pipeline portfolio to connect growing Marcellus and Western Canadian supply to key markets.Finally, in U.S. pipelines, a few comments on the recent FERC actions and their implications for our company. On July 18, FERC issued the final rule adopting certain revisions to the proposed FERC actions originally announced on March 15, 2018. As highlighted previously, we do not expect that the earnings and cash flows from our directly held U.S. natural gas pipelines including ANR, Columbia Gas and Columbia Gulf will be materially impacted, as a significant portion of their revenues are earned under nonrecourse rates.Further, as our ownership interest in TC Pipelines LP is 25%, the impact of the final FERC actions related to our MLP is not expected to be significant to our consolidated earnings or cash flow.Turning now to Mexico where we're advancing construction on 3 pipelines at a total cost for approximately USD 2.9 billion, offshore construction of the Sur de Texas pipeline was completed in May and the project continues to progress towards an anticipated in-service date at the end of 2018. 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 transportation service agreements.Turning now to our Liquids business, which produced very strong results again in the third quarter of 2018. Keystone continued to perform well, underpinned by long-haul take-or-pay contracts for 550,000 barrels a day. Grand Rapids and Northern Courier were both placed into service in the second half of 2017 and now are solidly contributing to EBITDA.In addition, we continue to benefit from a higher contribution from the liquids marketing, largely due to favorable marketing conditions, and that is expected to continue at least for the remainder of this year.Finally, a few comments on Keystone XL. In Nebraska, the Supreme Court is in the process of hearing an appeal case against the Nebraska Public Service Commission's alternative route. Legal briefs were submitted in May and oral arguments before the court begins today. We remain confident the public [ determination ] of the Nebraska Public Service Commission was lawful and expect the Nebraska Supreme Court could reach a decision by the first quarter of 2019.At the same time, 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 75% of the route in the state and expect that percentage to continue to rise.Finally, on the regulatory front, the U.S. Department of State issued a draft supplemental environmental impact statement or SEIS, on September 21. The SEIS concluded that the Mainline alternative route would have no significant environmental impact. The draft SEIS is open for public comment for 45 days, with the final SEIS expected to be issued sometime later this year.On the commercial front, in January, we successfully secured 500,000 barrels a day of firm 20-year commitments, which is consistent with the original level of contracting on Keystone XL prior to the denial of the presidential permit in November of 2015. The new contracts, combined with existing contracts on the Keystone system that convert to long-haul agreements on Keystone XL, means the Keystone XL would be largely utilized by contracted shippers after factoring in the capacity we required to set aside for spot shippers by our regulators.Potential shippers continue to express interest in the limited remaining capacity available on Keystone XL as well as any capacity that could be made available on the existing Keystone system. We are very optimistic that those discussions will lead to additional long-term take-or-pay commitments resulting in both lines being fully contracted.Turning to our Energy business. Construction on Napanee continues and is expected to be placed into service in early 2019 at a cost of approximately CAD 1.6 billion. 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 (sic) [2023].In late September, Bruce submitted its final cost and schedule estimate for Unit 6 major component replacement, to the Ontario IESO. While the IESO has up to 3 months to review and verify those estimates as both the cost and schedule duration are less than the thresholds defined in the program's life extension and refurbishment agreement, no further approvals from the IESO or the government is required to proceed with the project in early 2020. As a result, we expect to invest approximately CAD 2.2 billion in nominal dollars in Bruce Power's Unit 6 major component replacement program as well as ongoing the asset management program through 2023, when the Unit 6 refurbishment is expected to be completed.Bruce Power's current contract price of CAD 68 per megawatt hour is expected to increase into the mid-CAD 70 range in April of 2019, to reflect the capital to be invested under these programs as well as normal course inflation adjustments.Finally in Energy, last week we closed the sale of our 62% interest in the Cartier Wind project for proximally CAD 630 million. That sale allows us to [ surface ] significant value from a mature asset that represented approximately 5% of our generating capacity, and redeploy that capital into our CAD 36 billion secured capital program, thereby reducing our need for external capital, including common equity.In summary, the addition of the Coastal GasLink, the NGTL 2022 capital program and the Bruce Power's Unit 6 refurbishment, we are now advancing CAD 36 billion of secured growth projects that are expected to enter service by 2023.That 5-year plan includes approximately CAD 5 billion of maintenance capital, 85% of which is related to our regulated natural gas pipelines, and, therefore, is expected to be added to the rate base and generate a return on enough capital similar to what we realized on our expansion projects.To date, we've invested approximately CAD 14 billion of the CAD 36 billion into the program. These projects are all underpinned, as we've said before, by long-term contracts or rate-regulated business models. As a result, we have a high degree of visibility to the earnings and cash flows that will be generated as they enter service.In addition, we are advancing over CAD 20 billion of projects currently under development. And as we've said before, any one of those projects could further enhance our growth profile as well as our strong competitive position across North America.Based on our confidence in our growth plans, we expect to continue to grow our dividend at an average annual rate of 8% to 10% through 2021. As has always been our practice, the growth in dividends is expected to be supported by sustainable growth in earnings and cash flow per share and strong distributable cash flow coverage ratios.In summary, I would 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 services is ever-growing.With CAD 94 billion of high-quality assets, long life contractual and regulated terms, and 7,500 talented employees, we have 5 significant platforms for continued growth - our Canadian, U.S., and Mexico Natural Gas Pipeline divisions, Liquids Pipelines and Energy.As we advance our CAD 36 billion secured capital program, we expect to deliver significant additional growth in earnings, cash flow and dividends per share.In addition, we have more than CAD 20 billion of projects that are in the advanced stages of development and we expect numerous other growth opportunities to emanate from our extensive asset footprint across North America.Finally, we have a history of prudently funding our capital programs and are on track to achieve our targeted credit metrics without the need for distributed common equity to fund our current CAD 36 billion secured program.That concludes my prepared remarks, and I'll now turn the call over to Don, who will provide more details on our third quarter financial results. Don?
Thanks, Russ, and good morning, everyone. As outlined in our quarterly results issued earlier today, net income attributable to common shares was CAD 928 million or CAD 1.02 per share in the third quarter of 2018 compared to CAD 612 million or CAD 0.70 per share for the same period in 2017.Excluding specific items, comparable earnings of CAD 902 million or CAD 1 per share in third quarter 2018 were CAD 288 million or CAD 0.30 per share higher year-over-year. This equates to a 43% increase on a per share basis after giving effect to the diluted impact of common shares issued under our dividend reinvestment plan and at-the-market program. These, along with other funding activities, do, however, have us well on track to return to long-term targeted leverage metrics following the 2016 Columbia acquisition and continuing record capital program.Our positive results reflect operational strength and solid cash generation across all our businesses, particularly U.S. Natural Gas Pipelines and Liquids Pipelines and include the net benefits of the U.S. tax reform.Turning to our business segment results on Slide 15. In the third quarter, comparable EBITDA from our 5 operating businesses was approximately CAD 2.1 billion, a CAD 389 million or 23% increase in 2017. Canadian Natural Gas Pipelines comparable EBITDA of CAD 522 million was CAD 22 million lower than for the same period last year. I would note that for Canadian Natural Gas Pipelines, changes in depreciation, financial charges and income taxes impact comparable EBITDA but do not have a significant impact on net income, as they are almost entirely recovering revenues on a flow-through basis.Net income for the NGTL system increased CAD 9 million compared to third quarter 2017, as a result of a higher average investment base and continued system expansions, partially offset by lower incentive earnings, and reflects a base ROE of 10.1% on 40% deemed equity as approved in our 2018, 2019 rate settlement.Net income for the Canadian Mainline decreased CAD 9 million year-over-year, primarily due to incentives earnings recorded in third quarter 2017. Incentive earnings have not yet been recorded in 2018 pending an NEB decision on the 2018 to 2020 Tolls Review.U.S. Natural Gas Pipelines comparable EBITDA of USD 547 million or CAD 715 million in the quarter increased by USD 162 or CAD 233 million compared to the same period in 2017, mainly due to increased contributions from Columbia Gas and Columbia Gulf growth projects placed in-service, additional contract sales in ANR and Great Lakes, favorable commodity prices and throughput volumes in Midstream and increased earnings from the amortization of the regulatory liability recognized following U.S. tax reform.Mexico natural gas pipelines comparable EBITDA of USD 116 million or CAD 153 million was USD 22 million or CAD 35 million above third quarter 2017 as a result of increased revenues from operations due to changes in timing of revenue recognition and the third quarter 2017 impairment of our remaining equity investment in [ TransGas ].Liquids Pipelines comparable EBITDA rose by CAD 164 million to CAD 467 million in third quarter 2018, driven by the full impact of Grand Rapids and Northern Courier which began operations in the second half of 2017, prior volumes on the Keystone Pipeline System and a higher contribution for Liquids marketing activities.Energy comparable EBITDA decreased by CAD 17 million year-over-year to CAD 207 million due to a lower contribution from Eastern Power following the sale of Ontario Solar Assets in December 2017, narrower spreads realized by Natural Gas Storage and exclusion of U.S. power marketing contracts from comparable earnings commencing in 2018. These were partially offset by higher realized prices on increased generation volumes for Western Power and higher realized prices on lower outage days at Bruce Power.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, Canadian dollar translated EBITDA benefited from a stronger U.S. dollar compared to the same period in 2017. Conversely, year-to-date, U.S. dollar was modestly weaker compared to the first 9 months of 2017. This caused the foreign-exchange impact at the business unit level in the third quarter, 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 a reminder of our approach to managing foreign exchange exposure, our U.S. dollar denominated revenue streams are partially hedged by interest in 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 16. Depreciation and amortization of CAD 564 million increases CAD 58 million versus third quarter 2017, largely because new facilities entering service across our businesses and a higher [ depreciation ] rate on NGTL, partially offset by the sale of Ontario Solar assets in 2017 as well as cessation of depreciation on our Cartier Wind power facilities upon their classification as held-for-sale assets at June 30, 2018.Interest expense included in comparable earnings of CAD 577 million for third quarter 2018, was CAD 74 million higher year-over-year, following new debt issuances net of maturities, increased translated U.S. dollar denominated interest due to a stronger U.S. dollar and lower capitalized interest on liquids pipelines projects placed in-service in 2017, partially offset by increased investment at Napanee and the recommencement of capitalization of Keystone XL in 2018.AFUDC for the 3 months ended September 30, 2018, was in line with the same period in 2017.Comparable interest income and other decreased by CAD 10 million in the third quarter versus 2017, primarily as a result of realized hedging losses on foreign-exchange management in 2018 compared to realized gains in 2017, as well as income recorded in 2017 on termination of the Prince Rupert Gas Transmission project.Income tax expense included in comparable earnings was CAD 108 million in the third quarter of 2018 compared to CAD 163 million for the same period last year, primarily on account of reduced tax rates under U.S. tax reform and lower flow-through income taxes on Canadian regulated pipelines, partially offset by higher pretax comparable earnings.Excluding Canadian rate regulated pipelines where income taxes are a flow-through item and are, thus, quite variable, along with equity AFUDC income in U.S., and Mexico Natural Gas Pipelines, we continue to expect our 2018 full year effective rate to be in the midteens.Net income attributable to noncontrolling interest increased by CAD 15 million for the 3 months ended September 30, 2018, mostly due to higher earnings in TC PipeLines, LP.And finally, preferred share dividends were comparable to third quarter 2017.Now moving to cash flow and distributable cash flow on Slide 17. Record comparable funds generated from operations of approximately CAD 1.6 billion in the third quarter reflects an increase of CAD 255 million year-over-year, driven largely by higher comparable earnings as outlined.Comparable distributable cash flow in the quarter reflecting only nonrecoverable maintenance capital expenditures was approximately CAD 1.4 billion or CAD 1.56 per share compared to CAD 1.2 billion or CAD 1.34 per share in the third quarter of 2017, resulting in a coverage ratio of 2.3 times.As discussed on our second quarter conference call, 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 mirrors that of growth capital.Put another way, we expect to have the opportunity to recover and earn a return on 85% of our total maintenance capital expenditures through these mechanisms.Now turning to Slide 18. During the third quarter, we invested approximately CAD 2.8 billion in our capital program and successfully funded it through strong and growing internally generated cash flow, long-term debt issuance and common equity from our dividend reinvestment plan and at-the-market program.In third quarter 2018, we raised CAD 1 billion through a Canadian medium term notes offering comprised of CAD 200 million of 10-year notes at a fixed rate of 3.39% and CAD 800 million of 30-year notes at a fixed rate of 4.18%. After quarter end in October, we issued USD 1.4 billion of senior unsecured notes comprised of USD 400 million of 10-year notes at a fixed rate of 4.25% and USD 1 billion of 30-year notes at a fixed rate of 5.10%.Over the course of 2018, we have issued a total of CAD 6.1 billion long-term debt in the Canadian and U.S. capital markets, on compelling terms.Our dividend reinvestment plan, or DRP, continues to provide incremental subordinated capital in support of our growth and credit metrics. In the third quarter the participation rate amongst common shareholders was approximately 34%, representing CAD 213 million of dividend reinvestment. Year-to-date, the participation rate has been approximately 35%, resulting in CAD 655 million common equity at a 2% discount.In the third quarter, 6.1 million common shares were issued under our ATM program at an average price of CAD 57.75 per share, for gross proceeds of CAD 354 million, bringing the year-to-date total to approximately CAD 1.1 billion.We have now ceased ATM issuance, but do expect to operate our DRP for some portion of 2019. Going forward, we will continue to evaluate share count growth against further portfolio management activities, as our funding plan involves.To that end, in October, we closed the sale of our 62% interest on the Cartier power generation assets for approximately CAD 630 million, resulting in an estimated gain of CAD 135 million after-tax, which we recorded in the fourth quarter.Furthermore, an additional approximately CAD 400 million is expected to be realized prior to year-end, pursuant to elections by certain Coastal GasLink shippers to reimburse pre-FID development costs incurred by TransCanada. Together, the Cartier proceeds and Coastal GasLink capital recovery represent more than CAD 1 billion, to be applied against our capital program while serving to mitigate both leverage and rising share count.Now turning to Slide 19. This graphic highlights our forecasted sources and uses of funds in 2018, and illustrates that our funding needs for the year have been fully met. Our capital requirements continue to be financed in a manner consistent with achieving targeted run rate credit metrics in the range of 15% FFO to debt, and debt to EBITDA in the high 4s.Starting in the left column, our dividend and noncontrolling interest distributions of approximately CAD 2.8 billion, 2018 capital expenditures projected to be approximately CAD 10.5 billion including maintenance capital and long-term debt maturities of CAD 2.9 billion, bring our total funding requirement for 2018 to approximately CAD 16.2 billion.The second column highlights aggregate sources of approximately CAD 16.2 billion, including forecast full year internally generated cash flow of about CAD 6.4 billion and funding effectively in place of CAD 9.8 billion from long-term debt, commercial paper, cash on hand, DRP, the Cartier sale and the recovery of Coastal GasLink development costs as previously described.Note that we will pursue joint venture partners and project financing toward funding the CAD 6.2 billion Coastal GasLink project. The expenditure will be spread over approximately 4 years, with the bulk of the spend in 2020 and 2021.Although our external funding needs remain sizable, they will decline notably in 2019 in the absence of material new initiatives, and are eminently achievable in the context of multiple financing levers available and the clear accretive and credit support of use of proceeds.We reiterate that we do not foresee a need for discrete equity to complete our secured CAD 36 billion capital program.Now turning to Slide 20. In closing, I offer the following comments. Our solid across the board financial and operational results in the third quarter highlight our diversified low-risk business strategy and reflect a strong performance of both our blue-chip legacy portfolio along with the contribution of equally high-quality assets from our ongoing capital program.Today we are advancing a CAD 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, and we'll continue to make all funding decisions based on per share metrics.Our portfolio of critical energy infrastructure projects is poised to generate significant growth in high quality, long-life earnings and cash flow for our shareholders that is expected to support annual dividend growth of 8% to 10% through 2021.Success in adding to our growth portfolio in the coming years could augment or 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. If you have any further questions, please reenter the queue. With that, I'll turn it back to the conference coordinator.
[Operator Instructions] We have a question from Linda Ezergailis from TD Securities.
Appreciate the update on Keystone XL. There's a lot of moving parts in the various work stream. I'm wondering if you could help us, though, to [ slow ] it down to a sense of when the earliest you might get to an FID based on your expectation of when certain regulatory and legal processes can conclude? And also give us a sense of are there any sort of construction windows that you need to put next year that you might miss if you don't get to FID by certain point.
Linda, it's Paul Miller here. On the first question about the regulatory hurdles and the timing of those hurdles, there's 3 in place now. The first one is the challenge to the presidential permit in the Montana court. The judge has indicated that he will rule on the items by December 1. So we would anticipate a decision here over the next 2 months. The other challenge is the challenge to the approved route in Nebraska by the Public Service Commission. That is being challenged at the Nebraska Supreme Court. The written submissions are in. They were in last May. The oral argument is being held today. At that point, it's in the court's hands. And we would anticipate a decision from them in late December or early 2019. The third area of permitting is the permits from the Bureau of Land Management which governs the access to the federal lands and permits from the Army Corps of Engineers. The issuing agencies have indicated that with the expected issuance of the Supplemental Environmental Impact Statement here in early December, that they would issue those permits in early January. So with that, we continue our construction planning and preparation in anticipation of resolution of these legal and regulatory hurdles, prepare us for a start of construction in 2019. But we'll have to reflect on the rulings that do come down from the courts as well as the federal agencies. As far as construction activity, we have planned for a 2-year construction. That 2-year construction takes into consideration the various windows of construction we have and areas where we are not allowed to construct. The most significant would be in the northern part of the U.S., where there's various windows that are closed to us in that January to, let's call it mid- to late Q2 time period. So our planning works around those windows. So to the extent that we are able to proceed to construction in that time period, we would avoid those windows. And to the extent that our resolution of the legal and regulatory hurdles is not in hand until later in that period, we would start construction in those northern tiers in that June time period.
That's helpful context, Paul. Now I'm just wondering, as a follow-up, maybe this is more a question for Don. I realize we might be hearing this at your upcoming Investor Day. But can you give us a sense in the meantime maybe, how you're thinking of your options for financing Keystone XL? You've completed your financing requirements for 2018. I'm wondering if you might kind of accelerate your funding for 2019 and start thinking about the various levers for Keystone XL, depending on, obviously, timing of constructions then.
Yes. In terms of 2019, we're in very good shape entering the year. We actually have a sizable maturity, debt maturity in early January that I believe we've effectively prefunded with the activities we've undertaken to date. So we have a good start on 2019 already. In terms of Keystone XL, I'll reiterate the themes that we've discussed previously. Basically it'll be an all-of-the-above strategy. Keystone XL will bring hybrid capacity with it. As we've stated previously, we can issue hybrids up to about 15% of our capital structure. So as the balance sheet grows with Keystone XL, that would be one lever there. Portfolio management would pay more than a token role here. So we do have a sizable portfolio of salable assets contracted that we would be willing to part with to fund part of a Keystone XL program or, alternatively, to avoid share count growth in the future as well. We would entertain JV partners on this project. And other considerations would be, obviously, permutations of equity in the form of DRP, ATM and discrete equity for this. So basically everything's on the table here. We work towards final costing and see what the timing is. But again, it's an all-of-the-above strategy.
We have a question from Jeremy Tonet from JP Morgan.
Wanted to continue with equity here and just get a finer point on how you think about that going forward. So next year looks like it's just the DRP. But just wondering under what circumstances might you do the ATM or discrete equity offering again. Is it really just if projects are above the CAD 36 billion secured level? And is that kind of like the determining factor there is whether or not you would issue equity in any of those forms?
It's Don. Yes, we'll continue to look at everything on a per share basis. So if it makes sense for us to sell assets to avoid future share count growth, we'll do that. Depends on the nature and the magnitude of what might come in the door in addition to CAD 36 billion. We are gravitating back here towards our historical live-within-your-means doctrine. We want to eliminate DRP issuance here at some point in 2019. And then we'll see what comes in the door from there. These are all levers we can pull. But again, I'll just reiterate it. Everything's on a per share basis here. So in the absence of a major new initiative such as the Keystone XL, we think we're in pretty good shape here. And that's kind of our philosophy going forward.
That's helpful. And when it comes to portfolio management, just wondering if you could update us there as far as how you see the strength of that market. Has that changed at all? Or is it still kind of a strong market? We've seen some good multiples posted recently. And with Coastal GasLink, is there kind of a targeted ownership level that you would be comfortable with? Could you go below 50%? Or how would you think about that if you bring partners in there?
The bid is strong for contracted assets. And we're seeing that across our portfolio as we look at monetization candidates here. Some in the air, we could see like CAD 0.5 billion of contracted EBITDA as being candidates for sale. You put a reasonable multiple on that, and that could be a substantial source of funding for us going forward. And again, the amount of money looking for contracted infrastructure assets is substantial. That gravitates into Coastal GasLink. So we have seen substantial inbound interest in participating in that on a joint venture basis. In terms of where we would ultimately end up in terms of equity ownership, I give you a range of us retaining somewhere between 25% and 49% ownership post bringing in JV partners.
That's all very helpful.
The next question is from Ben Pham from BMO.
To continue on Coastal GasLink and with the Sawyer filing and the NEB looking at it in terms of jurisdiction, are you still moving forward to status quo of preparation CapEx spending looking to sell down the JV regardless of what's going on behind the scenes with the NEB? Are you taking more of a wait-and-see just given that there's a difference between the pipe in-service in the LNG in-service?
Ben, it's Karl. Let me just start by saying TransCanada is disappointed with the NEB decision to move forward to review jurisdictional matters here. We do know they have a job to do. We will be cooperating with that job and participating in that hearing. We are -- but I will say that we have valid permits from an appropriate regulatory agency right now, and we do intend to continue our construction process for this project as we speak. If something happens in the future where jurisdiction does change before we're finished construction, then we would expect a seamless transition of the [ premise ] just like we have experienced in other jurisdictional changes through the last history of TransCanada. So from our perspective we will cooperate and work with this hearing that they're going to have on jurisdictional matters, but we will also be starting our construction with the permits that we have.
Ben, it's Don here. In terms of the project financing and JV angle here, we've been working on the project financing for quite some time and the JV side is ramping up as we speak here. Given the spend profile of CGL where the bulk of the spend is in '20 and '21, there is no pressing need to get all this placed in the coming quarters here. That said, we continue to move towards that. At this point, we don't see it as materially impacting our funding plans and JV plans.
Okay. And then a second question following on some of the questions about the funding. And it seems like you're quite sensitive to the equity side of the balance sheet just to where your stock's moving and ceasing the ATM and maybe rely less on the DRP, maybe sell some more assets. So I wanted to clarify as part of that, is there a little tweak the dividend language in the slide? I know 8% to 10% is still quite strong issue leading. You guys can certainly throw out those levels. But there's a little bit of a different positioning on that versus Q2?
Yes. It's Don here. The nuance is we -- the words upper end aren't there. It shouldn't be construed as -- we may be at the upper end and this should not be seen as any downgrade of our expectations in the future. Our commitment to 8% to 10% is certainly reaffirmed through 2021. It is affordable and it's within our long-term, long-established payout metrics. On balance, it provides us some latitude as we look at credit metrics, growth profiles. And philosophically on the margin, if it makes sense to not grow the dividend quite as quickly, we're talking marginal dollars here, but philosophically to avoid share count growth at something in the low 50s, high 40s here, that's really where we're coming from on this.
Okay. We generally agree with that.
We have a question from Robert Catellier with CNBC Capital Markets.
I just want to understand what level you might sell Keystone XL down to, understanding that there's a lot of other levers that would result in that decision. But what level of asset sales, for example, would you have to attain in order to retain 100% of Keystone XL?
Robert, it's Don here. We really haven't landed a number at this point. This is a very attractive project. But what we're trying to convey here is we'll look at everything on a per share basis. So we haven't landed any specific range in what we would sell down to. It may be nothing. And we'll balance that against the equity requirement there. So as we finalize costs and what else is on our plate, that'll inform our decision on that front. As well, we will go to all of the rating agencies as we did prior to Coastal GasLink, and then engage the rating advisory services on various financing scenarios and see what the outcome is there. So quite a ways to go before we land on anything on that front.
Robert, I think as we've always approached these things, as Don mentioned, we've got several opportunities to monetize various assets in our portfolio. They're very attractive to market, as is an interest in Keystone XL and will be driven by long-term shareholder value. So the components of the analysis include what is the implied cost of capital? And as always, we seek to find the lowest cost of capital amongst the various levers we have in front of us. And until we get through the analysis and have conversations with people, we can't make that call. But I think the message that we're sending today is that we have several levers to rely upon. As you know, our most extensive cost of capital, especially at the current time, is equity, and we're very sensitive to that. So we're looking at other levers in our portfolio. And we're very comfortable with the flexibility that we have there and are comfortable in our ability to finance our programs, including Keystone XL, going forward.
Okay. And then just I'm a little curious as to why the regulated maintenance capital expenditure for Canadian Mainline has changed. It looks like it's down to 1.9 from 2.5. What's behind that?
Yes, Robert. It's Karl. Maybe I can just say this. We're always refining our estimates of maintenance, especially maintenance capital. You have to remember our views with equipment performance usage need on our system. So a changing on maintenance capital is not all that unusual. I will say that we have been at elevated levels last few years as we've been increasing the volumes in our system. As our system gets more full, we need to put more maintenance in. I would suggest kind of on a long-term basis for the Canadian, most of this decrease that you referred to came out of the Canadian, I guess pipeline systems. Again I would suggest on a long-term, we'd be looking at maybe CAD 600 million a year of maintenance capital coming out of the Canadian system. So that's down over the forecast period, than what you've seen the last couple years. But I'd say CAD 600 million's a good run rate. As our system becomes more heavily utilized, you'll see it go up a little bit temporarily, but it should always --it should always adjust back to the 600 million range.
Fantastic.
The next question is from Tom Abrams from Morgan Stanley.
Couple quick ones and then a little bit longer one. But the 2 quick ones are, your balance sheet ratio that you expect at the end of the year, let's start with that.
It's Don here. In terms of debt to EBITDA?
Debt to EBITDA, yes.
Yes. We'll be within the range as expected by the rating agencies as we continue to delever post-CPG and get those assets in-service. How I describe it is, the run rate as we bring the CAD 10 billion of assets, as Russ outlined into service here over the coming months and with our expected cash flow from them, we should be on side with that 5x debt to EBITDA, 15% FFO to debt, on a run rate basis as we exit this year into early 2019.
Okay. The other quick one is, when you say the finalize cost for Bruce Power, I think you said CAD 2.2 billion, that's finalized with the regulators or with the -- or that's not something you've done with the contractors?
Yes. So it's like costs that we've put out there for Unit 6 is the full cost of both the major component replacement and the asset management through to 2023. And that is a cost that we have actually -- it's accumulation of costs from the contracts we've put up for all of our various subcontractors and equipment suppliers. So when we put that CAD 2.2 billion out there, that's our 50% share of the full cost of Unit 6 replacement. Both the major component [ waged on any ] asset management. So that cost I was just pointing out is under the kind of threshold that we had in the original contract. So there is no real decision on goal or no goal. The IESO right now is just making sure our project is complete. And they will probably be issuing sometime in November kind of their comments on that. But we're expecting to proceed as per our proposal to them. You will see the adjustments in the rates for Bruce coming in at the beginning of April. We will as Russ said in his opening notes, we will adjust the price per megawatt hour that we sell to them up from CAD 68 to the mid-70s. You'll see that starting April 1. And Unit 6 comes off on beginning of 2020. So in January of 2020. So we will actually be collecting the monies before the Unit 6 comes [ on ].
Okay. And then my last question was just how you're thinking about TCP these days.
It's Don here. There's still some regulatory process to go through for the assets in there. So we're still looking to clarify exactly what the long-term cash flows are from that. I would describe TCP as either a source or use of capital at this time and just leave it at that.
I appreciate it. We'll see you in a couple weeks.
The next question is from Robert Kwan with RBC Capital Markets.
Maybe if I can come back to funding and looking out to 2019. If you just look at the secured capital program, so no kicks on any large projects that would actually add to the 2019 program. I guess you're messaging the ATM is going to be off. The DRP's going to be on for some portion of the year. How does portfolio management work into your base plan for 2019? Has the decision, as you look at this kind of share count metric the decision being to leave the DRP? Or is portfolio management some amount in the 2019 numbers, as well, on top of the DRP?
It's Don here again. At this point, with the dividend declaration today, the DRP will be on certainly for the January dividend payment. So as we look to the balance of the year, DRP could go anywhere from a couple quarters to the full year depending on the capital program and portfolio management. So you shouldn't take silences in activity on the portfolio management front. And we do have a number of items in the fire right now. But it's really give-and-take as to those processes getting to suitable finish lines and what more we might look at. But certainly DRP for some portion of the year. The potential is for it to be there all year. But if we can truncate that with sensible attractive portfolio management, we'll do that.
Okay. And then just if I can refine the 2018 EPS outlook. And I don't know if you want to tie it back to the second quarter guidance. But when you're talking about fourth quarter looking like the first 9 months, so is that an annualization of the 9-month figure? Or again, if you want to tie it back to second half is going to look like the first half. Just if you can refine the message.
Yes. It's Don here. It's the quality of what you've seen over the first 9 months. There's a little bit of seasonality in our business, particularly in the U.S. gas pipeline side. But I would see that the strength you've seen through 9 months here continuing into the fourth quarter and through 2019 as well here. So as you know, we don't give specific point EPS guidance. But is it 4/3 of what you've seen year-to-date? I won't get that granular. But factor in the seasonality and continue the strength you've seen.
Put differently though, is there nothing wrong, at least as a baseline from the statement you made for Q2, second half looks like first half?
Yes.
The next question is from Rob Hope from within Scotiabank.
Want to circle back on the commentary regarding joint ventures for both Coastal and Keystone. Arguably, you've created value through the development process of these assets. Just wondering how you would look to capture that through a JV arrangement. Could you get an upfront payment? Would it be more of a promoter? How are you thinking about JVs there?
Robert, I think as I mentioned earlier and you've just highlighted, these projects are well constructed and highly contracted and, therefore, are very attractive in the private markets currently. And we're just going through that process right now to determine what is that value that can be created? And what's the best way to surface it for our shareholders? So I'd say at the current time we haven't concluded. But I would say that a promote either upfront or over a period of time wouldn't be unexpected. That we think that there's considerable value in here for our shareholders and we would look to surface that. And to maximize value first is not to give up value. And so how we go about doing that in any negotiation will be with that focus. And then secondly, mindful about our current financing requirements, and to the extent that any upfront payments or things like that can be used to offset equity issuance, obviously that would be a consideration in our valuation of various potential partners. So as Don, I think alluded to, A, we're very comfortable with the array of options that we have in front of us and that we'll look to optimize those options to best fit both long-term shareholder value and to minimize share count growth.
Yes. It's down here. We're always cognizant of balancing complexity, structural subordination and control of these assets as well. So there are some other qualitative factors we bear in mind here.
All right. Appreciate that. And then just I guess moving over to the NGTL system, the expansion that you've announced last night. More broadly, how are we thinking about the supply/demand balance out of Western Canada now that you have LNG moving forward? Could we see less of an emphasis on longer-term contracts eastwards out of the basin and more focus on westwards?
Robert, it's Karl. So I guess my feeling on that is that there's enough resource base, there's enough producability in that resource base that we can have -- it's not an either/or anymore, it's both. So even though there's obviously going to be, in the next 4 or 5 years, a very robust Western market for the natural gas going through Coastal GasLink. We're still working as hard as we can to move gas molecules into Eastern Canada and into the Midwest down into our U.S. pipelines for further transport into the Gulf Coast even, if that works some. So I think given the nature of the resource there and just the sheer amount of gas and producability of it, I think it behooves us to continue looking for markets for our producer customers. So that's what we're going to continue doing.
I'll just augment Karl's comments. There's over 1,000 Tcf recoverable reserve in the Western sedimentary basin. I think it's proving itself to be one of the lowest cost most prolific basins in North America, if not the world, currently producing in the 17 billion cubic feet a day kind of range. You could kind of look at a similar basin in the Appalachian that went from 0 to 40 in a very short period of time because it had access to market as an example of where we think the basin can go long-term. We believe it's only constrained by market access and, therefore, as Karl said, that's what we're working on both to the West Coast and south to California into the Midwest and even into the Northeast U.S. And as we've seen in recent open seasons, you have the [ RT ] U.S. utilities and even Eastern Canadian, far Eastern Canadian utilities are interested in Western sedimentary basin. So as we look forward, I think, as I mentioned in my opening remarks, Coastal GasLink has the ability to expand to 5 Bcf a day. And we fully expect that over time that's an economic proposition for Shell and its partners, that that's a probability going forward. The open seasons that we've had downstream as well, I think as we noted in our release, growing intra-basin markets, the growth in power generation as we convert from coal-fired generation to gas-fired generation increase gas-fired generation, the industrial development that's coming with petrochemical development as we look to value-add products here in the province of Alberta. All of those things are new markets which will bolster growth. So we actually don't view the basin as being limited in that 20 Bcf a day range. If we can create market access, there's no reason why the basin can't grow conservatively more than that. So as Karl said, primary focus for our Canadian gas business right now is around developing markets for our customers to allow them to continue to increase production.
Yes. Just to give you a feeling for this latest expansion, 2/3 of that expansion, kind of physical volume-wise is for the new intra-basin market and 1/3 will be receipt. Of the cost of the expansion, probably 80%, 90% of it will be to go hook up that intra-basin market, and about 10% to 20% of it will be for the receipt. So most of this expansion that we brought forward is actually -- it is market expansion for production.
The next question is from Andrew Kuske from Crédit Suisse.
I think the question's probably for Paul, and it just relates to the liquids unit and the marketing numbers that you posted this quarter, which were impressive. If you could just maybe give us a little bit of color and context around what happened in the quarter, and then expectations on a go-forward basis.
Certainly, Andrew. We did see strong results from our marketing entity in the third quarter. Our marketing entity has capacity on various pipes. And with that capacity they hedged their position. And the vehicle they hedged their position largely is around the Brent TI spread. And what we saw in the third quarter, and let's call it the third quarter business cycle which precedes, if you wish, calendar quarters. We saw a significant increase in those differentials kind of in that May timeframe. And we're able to pick up some of that value before the decline. And then after the decline, the market came back. So I would expect to see our marketing results in Q4 to be similar and maybe even an increase to what we saw in Q3. When we look forward to the forward curves on the various differentials, I would anticipate similar results for our marketing entity into calendar '19.
Okay. That's very helpful. And then maybe just a follow-up. Just operationally on Keystone, what are you running volumes at? And have you managed to eke out any picture capacity either by way of scheduling, batching, DRA?
Certainly. So I'll answer from two perspectives. The ex-operator Keystone System has capacity of 590,000 barrels per day, and that's our authorized capacity. And of that capacity, we've contracted up 555,000 barrels per day. And that's about 94%. And we are required to set aside 6% for spot. And with the differentials we're seeing out of Alberta, there's the high demand for that spot. So we are effectively running full on the Keystone System. On the southern leg, our Marketlink system, which runs south of Cushing, that's a pipe that has run probably in that 300,000 to 400,000 barrel per day range historically. But over the course of the last year, we have looked to increase the capacity on the capability of that line. We've increased that capability to probably the mid 600,000 range. And with, again, the differentials we're seeing between Brent and TI, we're flowing in that range in that low to mid-600,000 barrel per day range. Now, of that capacity, our strategy has always been and will continue to be pursue sustainability and pursue quality. So we take the opportunities as the capacity increases and as the market demand increases, to term out some of these volumes. So on the Marketlink system, of that capacity, we're probably running about 80% contracted. So again, I see a sustainability for the Keystone system as well through Q4 and into our calendar '19.
The next question is from Praneeth Satish, Wells Fargo.
I was just wondering if you could provide just a general update on Mexico, I guess just what you're seeing there and how guess demand is tracking relative to your expectations.
Yes. It's Karl. So maybe I can just kind of update a little bit on our [ section ] program. The Sur de Texas, which is the large offshore pipeline that we're working on, we're in pretty good shape on that, actually. We've had some rough seas the last few weeks, so we've got our boats in dock. But it's really we have one more area of tie-in, land-to-sea tie-in to do, and then we'll start calling for gas. So we're still predicting an end-of-the-year in-service. With the rough weather we've had, maybe it's slipped. But I'm talking days and maybe a few weeks, not anything longer than that. So right now, the seas are calm and we'll be moving our pipeline off shore to get it interconnected. So that'll happen over the next couple weeks, hopefully, barring any unusual weather patterns. Our Villa de Reyes has come along fine. As you know, the Villa de Reyes is the pipeline that has run into all the artifacts. I think we ran into like 90 archaeological finds as we were doing that pipeline. That doesn't stop the pipeline indefinitely, but it does slow it down as we have to wait for the government of Mexico to investigate all these archaeological finds. So it has been delayed. We are, I will point out that because of the force majeure that we've had on all pipelines, Tulla, Sur De Texas and Villa de Reyes, we are collecting actually our revenue on them right now. We have contacts that say if the delays are not -- if they're not from TransCanada's doing, that we can collect our revenues on them. So we are collecting the revenues on them, even though they haven't gone into service. We expect the Villa de Reyes to be in-service in 2019, as we clear up all the archaeological sites and we move on. We will bring that in next year. Tulla is a pipeline that we have actually demobilized on. We have actually pretty much finished everything we can construct on there. And we have one-90 kilometer section of aboriginal issues, which is a government of Mexico obligation to sort out. We're still hopeful they'll get that sorted out sometime in '19, and we can finish. We are hoping that we can put it partially in-service before then. And again, we are collecting all of our revenue on that pipeline, because that is a force majeure. That fits the definition of that allows us to collect our revenue. So I think our projects are going fine in Mexico. We are looking forward to next year completing them, say for Tulla, completing them all and putting them all in physical in-service. We did put the Topolobampo in-service this year after similar indigenous issues. It is flowing gas right now. So we're looking forward to next year to get this system operationalized and flowing gas.
And then just turning to the balance sheet quickly, if you pursue project financing for Coastal GasLink, will the rating agencies treat that debt as completely off balance sheet? Or will they consider your proportionate ownership of that debt?
It's Don here. To be determined. And again as I mentioned, but for K XL and what we did with Columbia, we will engage the agencies' rating advisory services as we look through that. It depends how it's structured, obviously commercially and what covenants and conditions are on that. But we would be hopeful to achieve proportionate consolidation of that debt.
The next question is from Patrick Kenny from National Bank.
Wanted to get your thoughts on East Coast LNG. Pieridae looks to be closing in on FID. What this could mean for new long-term contracts down the Mainline over the near term as well as what the expansion opportunities might look for TQM and BNGGS.
It's Karl again. Yes, we have been in discussion with several developers on the East Coast of Canada. I will say that the developers there, both Pieridae and others, they have been -- they seem to be well-financed. They seem to be progressing. They seem to be progressing in their project development. To date, we do not have any transportation agreements with any of them. So we are still discussing with all of them kind of what services that we can offer. Obviously, if an East Coast LNG does go ahead, we are interested in expanding our system to accommodate that. Right now, most proponents are looking to use our system up to Portland and then going through Portland and may be utilizing the Maritimes northeast infrastructure until that is full. So that's kind of the probables you're looking at. Although that can accommodate a lot of gas. It can probably accommodate -- it can't probably work with one of the projects. But as I said, yes, to date, we don't have any transportation agreements with any of them. So we'll continue working with them. And as their projects progress and get more mature, we'll be dealing with their requests for transportation services at that time.
All right. Sounds good. And then maybe just a quick follow-up on your comments on the NGTL expansion announced yesterday, from an Alberta demand [ pool ] perspective. Just based on your internal forecast, do the expansions announced yesterday fully cover what's needed for coal to gas power conversions, petrochemical growth, oil sands growth into next decade? Or could we expect the phase 2 expansion on NGTL related to these Alberta customers at some point in-service beyond 2022?
That's a good question. That's something obviously we ask ourself all the time. So let me say this. For the intra-basin demand, I think these are the requirements that were in our queue at this time. These should, I think a portion of it, obviously, is for coal-to-gas, a portion is for chemical. These are what proponents have come and asked us right now that they're willing to sign up for. We do have ongoing discussions with other potential increases in intra-basin market that we're working outside of this. And they may or may not come to fruition in the future. So I find it hard to say that this will take care of us for a long period of time because this is a growing intra-basin market. But this is all we have right now. These are the people that were willing to set up and sign contracts for us.
The next question is from Alex Kania from Wolfe Research.
This is just a follow-up on Mexico. We just seen a little bit of volatility in the markets down there over the past week or so just with respect to the, I guess the airport decision by Obrador. Is there anything that we should read through to that on the existing projects? I know that you don't have a lot of kind of incremental capital to be deployed there. But just kind of considering what your thoughts are on that.
It's Karl. And I'm aware of the issue that you're talking about. But I guess I can say this. We haven't had a lot of exposure to this new administration. They will be kind of in place here late this year in the new year, and we do expect to become more involved with them and to get into all the ministry offices and whatnot and have more thorough conversations with them. And I might be able to answer this a little bit more directly at that time. But from where I sit right now, natural gas, their natural gas strategy and just natural gas into Mexico is very important for the future growth of the Mexico economy. It's important for their power plants. There's a great strategy to replace oil with gas and sell the oil internationally. There's a great strategy for them to get industrials using cheaper natural gas rather than fuel oil in their processes. So it's a very important element of the future growth of their economy. And I would expect our infrastructure plays a very critical part of that [indiscernible]. So my expectation is that the government will work with us to make sure that this infrastructure plays an important part in this economy. And my expectation is that once they're in place, we will be working well with the government to make sure that these guys' pipelines are fully utilized and the benefits to Mexico are realized through the work we do. So from right now, it's so important for the Mexico economy, I just can't envision anything other than us working together to make sure that we get the full use, both Mexico and TransCanada gets the full use of these assets.
The next question is from Shneur Gershuni from UBS.
This is actually [ Ida ] for Shneur. So my first question is do you see a need to twin or expand Marketlink to have incremental volumes from Keystone XL? Could you please talk about the market dynamics there? Thank you.
Certainly, [ Ida ]. It's Paul here. Where we're focused right now is, you can see our various projects, including Keystone XL. But part of our opportunities around both the legacy systems and Keystone XL kind of revolves around the footprint we have. We have a very good footprint which starts in northern Alberta and moves straight down the midcontinent to the U.S. Gulf Coast. So we're always looking for opportunities to secure additional and growing supplies and deliver them to market. And at this point, market dynamics on the Gulf Coast look quite attractive. As I indicated earlier, there are some high differentials. We do see 2 or 3 different pipe proposals in play now and under construction. So we'll see how that market dynamic plays out here over the next year to determine what our go-forward is going to be. Our approach to business development is to always secure long-term contracts for our infrastructure. And on Keystone XL, which we'll use a portion of that Marketlink capacity, we have these 20-year contracts. To the extent that the marketplace requires an additional pipe flowing from Cushing down to the Gulf Coast and we can secure long-term contracts for that infrastructure, that's certainly business we can [indiscernible].
Perfect. That's very helpful. I have also 1 more question on funding. So do you have some color around funding plans should Keystone XL be FIDd? And when you think about your long-term target, what's your willingness to consider leverage ratio below 5x and save 4.75x? Thank you.
Yes. It's Don here. I did address that earlier in terms of how we would approach Keystone XL funding. So I would refer you to that answer. In terms of the credit metrics, as I mentioned, we will engage the rating advisory services of the credit rating agencies with other various funding scenarios to see what the impact would be. At the end of the day, we want to return to high 4s debt to EBITDA ratios as a run rate and minimum 15% FFO to debt. How that works through a construction period is pursuant to discussions between us and the rating agencies.
We have a question from Harry Mateer from Barclays.
Just a follow-up to that last question. Not to split hairs. But Moody's has viewed sort of 5x and above, 5.0 and above is a potential downgrade trigger. So it sounds like maybe a bit of a shift to high 4s, although you're still consistent with 15% FFO to debt. Can you just talk about how you view the value of that A3 rating at Moody's? Is it important or less important, given S&P took you guys down earlier this year and you still have access to low-cost debt capital?
Yes, the A rating is important to us. But we'll take a balanced approach to it. If there is a significant moving of the goalpost, we need to factor in both equity and debt holders as to how we look at that. The high 4s guidance that we're giving here, we're not going to redline this. The intent is to give us some headroom there. And it is a very predictable business model. So we can see these cash flows for a very long period of time. So the intent is to be onside with that and the metrics that have been outlined for us. I wouldn't say the split rating between S&P and Moody's has changed our philosophy on this at all. So we'll just continue to fund this company the way we've done it for the past 15, 20 years here. And the right-hand side we put substantial subordinated capital on the books here since the Columbia acquisition. And I would say the left-hand side of the balance sheet has never been stronger in terms of the asset base and the longevity of the cash flows there.
We have a question from Joe Gemino from the Morningstar.
I have a quick question regarding any thoughts that you may have on bridges. Mainline, if you could expand a little more on what you think about them pursuing long-term take-or-pay contracts and what impact that may have on the Keystone and Keystone XL.
I wouldn't want to comment on projects and pipelines that we're not involved in. What I can tell you, I guess just to reiterate both my comments and Paul's, is the demand for our existing system and for Keystone XL has never been greater. Obviously you can see by the differentials in the marketplace that producers want access to markets and they are willing to sign long-term contracts. So the guidance that we've given you with respect to both fully contracting base Keystone and Keystone XL are consistent with that, as we believe that we'll -- our current operating results would, I guess indicate, yes, the demand for our system is great today. And what we're seeing from shippers both producers and refiners that want a contract on a 20-year basis, that that demand remains strong as well and we'd expect to fully contract. I can't really comment on anybody else's projects, though.
I appreciate that.
Ladies and gentlemen, the call has now concluded. If there's any further question, please contact TransCanada Investor Relations. I would now like to turn back the meeting over to Mr. Moneta. Please go ahead, sir.
Thanks very much and thanks to all of you for participating this morning. We very much appreciate your interest in TransCanada and look forward to speaking with you again soon. Bye for now.
The conference has now ended. Please disconnect your lines at this time and we thank you for your participation.